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  • 1. Manual of Petroleum Measurement Standards Chapter 8-Sampling Section 2-Standard Practice for Automatic Sampling of Liquid Petroleum and Petroleum Products SECOND EDITION, OCTOBER 1995 I American Testing and Society for Materials D4177 I I American National Standards Institute ANSVASTM D4177 I American Petroleum InstituteCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 2. A P I M P M S * 8 * 2 9 5 6 0732290 0549030 220 6 Manual of Petroleum Measurement Standards Chapter 8-Sampling Section 2-Standard Practice for Automatic Sampling of Liquid Petroleum and Petroleum Products Measurement Coordination SECOND EDITION, OCTOBER 1995 American Petroleum InstituteCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 3. A P I MPMS*8*2 95 m 0732290 05490LL Lb7 W SPECIAL NOTES 1 . API PUBLICATIONS NECESSARILY ADDRESS PROBLEMS OF A GENERAL NATURE. WITH RESPECT TO PARTICULAR CIRCUMSTANCES, LOCAL, STATE, AND FEDERAL LAWS AND REGULATIONS SHOULD BE REVIEWED. 2. API IS NOT UNDERTAKING TO MEET THEDUTIES OF EMPLOYERS, MANU- FACTURERS, OR SUPPLIERS TO WARN AND PROPERLY TRAIN AND EQUIP THEIR EMPLOYEES, AND OTHERS EXPOSED, CONCERNING HEALTH AND SAFETY RISKS AND PRECAUTIONS, NOR UNDERTAKINGTHEIR OBLIGATIONS UNDER LOCAL, STATE, OR FEDERAL LAWS. 3. INFORMATION CONCERNING SAFETY AND HEALTH RISKS AND PROPER PRECAUTIONS WITH RESPECT TO PARTICULAR MATERIALS AND CONDI- TIONS SHOULDBE OBTAINED FROM THE EMPLOYER, THE MANUFACTURER OR SUPPLIER OFTHAT MATERIAL, ORTHE MATERIAL SAFETY DATA SHEET. 4. NOTHING CONTAINED IN ANY API PUBLICATION IS TO BE CONSTRUED AS GRANTING ANYRIGHT, BY IMPLICATION OR OTHERWISE, FOR THE MANU- FACTURE, SALE, OR USE OF ANY METHOD,APPARATUS, OR PRODUCT COV- ERED BY LETTERS PATENT. NEITHER SHOULD ANYTHING CONTAINED IN THE PUBLICATION BE CONSTRUED AS INSURING ANYONE AGAINST LIABIL- ITY FOR INFRINGEMENT OFLETTERS PATENT. 5 . GENERALLY,APISTANDARDSAREREVIEWEDANDREVISED,REAF- FIRMED, OR WITHDRAWNAT LEAST EVERY FIVE YEARS. SOMETIMES A ONE- TIME EXTENSION OF UP TO TWO YEARS WILL BE ADDED TO THIS REVIEW CYCLE. THIS PUBLICATION WILL NO LONGER BE IN EFFECT FIVE YEARS AF- TER ITS PUBLICATION DATE AS AN OPERATIVE AFI STANDARD OR, WHERE - AN EXTENSION HAS BEEN GRANTED, UPON REPUBLICATION. STATUS OF THE PUBLICATION CAN BE ASCERTAINED FROM THE API AUTHORINGDEPART- MENT [TELEPHONE (202) 682-8000]. A CATALOG OF API PUBLICATIONS AND MATERIALS IS PUBLISHED ANNUALLY AND UPDATED QUARTERLY BY API, 1220 L STREET, N.W., WASHINGTON, D.C. 20005. All rights reserved. No part of this work may be reproduced, stored in a retrieval system, or transmitted by any means, electronic, mechanical, photocopying, recording, orother- wise, without prior written permission from the publisher. Contact API Publications Manager, 1220 L Street,N.W., Washington, DC 20005. Copyright O 1995 American PetroleumInstituteCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 4. A P I MPMS*&-2 95 E 0732290 0 5 4 9 0 3 2 O T 3 m. CONTENTS Page. O INTRODUCTION ................................................................................................. 1 1 SCOPE ................................................................................................................... 1 2 REFERENCES ...................................................................................................... 1 3 DEFINITIONS ...................................................................................................... 1 4 SIGNIFICANCE AND USE ................................................................................. 2 4.1 Applicable Fluids ........................................................................................... 2 4.2 Nonapplicable Fluids ...................................................................................... 2 5 REPRESENTATIVE SAMPLING CRITERIA ..................................................... 2 6 AUTOMATIC SAMPLING SYSTEMS ............................................................... 3 7 SAMPLING FREQUENCY .................................................................................. 3 8 STREAM CONDITIONING ....................................................................... :.........4 8.1 General ........................................................................................................... 4 8.2 Velocities and Mixing Elements .................................................................... 4 9 SPECIAL CONSIDERATIONS FOR MARINE APPLICATIONS ........ ............4 ~ 10 PROBE LOCATION AND INSTALLATION ....................................................... 4 1 1 PROBE DESIGN ................................................................................................... 5 12 EXTRACTOR ....................................................................................................... 5 13 CONTROLLER ..................................................................................................... 5 14 SAMPLER PACING ............................................................................................. 5 14.1 Custody Transfer Meters .............................................................................. 5 14.2 Special Flow Meters ..................................................................................... 5 14.3 Time Proportional Sampling ........................................................................ 5 15 PRIMARY SAMPLE RECEIVERS ...................................................................... 6 15.1 Stationary Receivers .................................................................................... 6 15.2 Portable Receivers ........................................................................................ 7 15.3 Receiver Size ................................................................................................ 7 16 SAMPLE MIXING AND HANDLING ................................................................ 7 17 PORTABLE SAMPLERS ....................................................................................... 7 17.1 Design Features ............................................................................................ 7 17.2 Operating Considerations ............................................................................. 8 18 ACCEPTANCE TESTS ......................................................................................... 8 18.1 General ......................................................................................................... 8 18.2 Total System Testing .................................................................................... 8 18.3 Component Testing ...................................................................................... 8 18.4 Requirements for Acceptability ................................................................... 8 19 OPERATIONAL PERFORMANCE CHECKSREPORTS .................................. 9.. iiiCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 5. . APPENDIX A-ACCEPTANCE METHODOLOGIES FOR SAMPLING SYSTEMS AND COMPONENTS ................................................... 11 " APPENDIX B-THEORETICAL CALCULATIONS FOR SELECTING THE SAMPLER PROBE LOCATION ............................................. 17 APPENDIX C-COMPARISON OFPERCENT SEDIMENT AND WATER VERSUS UNLOADING TIME PERIOD ........................................ 23 APPENDIX D-mQUENTLY USED FORMULAS AND EQUIVALENTS .........25 APPENDIX E-DESIGN DATA SHEET FOR AUTOMATICSAMPLING SYSTEMS ......................................................................................... 27 APPENDIX F-PERFORMANCE CRITERIA FOR PERMANENT INSTALLATIONS ............................................................................ 29 APPENDIX G-PERFORMANCE CRITERIA FOR PORTABLE SAMPLING UNITS ............................................................................................... 31 APPENDIX H-PRECAUTIONARY INFORMATION ............................................. 37 APPENDIX I-SAMPLER ACCEPTANCE TEST DATA SHEET ............................ 39 Figures 1-Typical Automatic Sampling Systems ............................................................... 3 2-Recommended Sampling Area .......................................................................... 5 3-General Vertical Piping Loop Configuration ..................................................... 5 4-Probe Designs .................................................................................................... 6 5-Stationary Receiver(s) Installation .................................................................... 6 6-Portable Receiver(s) Installation ........................................................................ 7 7-Typical Portable Marine Installation ................................................................. 7 A-1-Sequence of Acceptance Test Activities ........................................................ 12 A-2-Multipoint Probe for ProfileTesting ............................................................. 14 C- l-Comparison of Percent Sedimentand Water Versus Unloading Time Period ................................................................................................... 23 . G- 1-Typical Piping Schematic to Recorded for Loading ................................ Be 34 G-2-Typical Piping Schematic toBe Recorded for Discharges ............................ 35 Tables l-General Guidelines forMinimum Velocities Versus Mixing Elements .............4 A-1-Allowable Deviations for the Single and Dual Sampler Water Injection AcceptanceTests .................................................................. 13 A-2-Typical Profile Test Data, in Percent Volume of Water ................................. 15 A-3"Calculation of Point Averages and Deviation ................................................ 15 B-1-Comparison of Mixing Devices ..................................................................... 18 B-2-Dispersion Factors ......................................................................................... 18 B-3-Suggested Resistance Coefficients ................................................................ 19 B-&Dissipation Energy Factors ............................................................................ 19 B-5-Dissipation Energy Relationships .................................................................. 19 G-1-Portable Sampler OperationalData Confirmation of Mixing and Flow Sensor Velocity ............................................................. 32 G-2-Portable Sampler OperationalData Confirmation of Free Water Sampled ................................................................................. 33 . ivCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 6. A P I MPMS*B-Z 95 m 0732290 0549034 976 m FOREWORD API publications may be used by anyone desiring to do so. Every effort has been made by the Institute to assure the accuracy and reliability the data contained in them; however, of the Institute makes no representation, warranty, or guarantee in connection with this pub- lication and hereby expressly disclaims any liability or responsibility for loss or damage resulting from its use for the violation of anyfederal, state, or municipal regulation with or which this publication may conflict. Suggested revisions are invited and should be submitted to the Measurement Coordina- tor, Exploration and Production Department, American Petroleum Institute, 1220 L Street, N.W., Washington,D.C. 20005. VCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 7. API N P N S * d . Z 75 0732290 0549035 8 0 2 Chapter 8-Sampling SECTION 2-STANDARD PRACTICE FOR AUTOMATIC SAMPLING OF LIQUID PETROLEUM AND PETROLEUM PRODUCTS O Introduction D4057 Manual Sampling of Petroleum and Petroleum Products (also API MPMS Thisdescribes standard methods and equipment to used Chapter 8.1) automatically obtain representative samples of petroleum D4928 Water in Crude Oils by Coulometric Karl and petroleum products flowing throughpipeline. a Fischer Titration (also API MPMS Chap- ter 10.9) GPA2 1 Scope GPA 2166 Obtaining Natural Gas Samplesfor This standard provides information the design, instal- for Analysis by Gas Chromatography lation, testing, and operation of automated equipment for IP~ extraction of representative samples of petroleum and IP PetroleumMeasurement Manual, Part VI, Section 2 petroleum products from a flowing stream andstoring them in a samplereceiver. If sampling is for the precise determi- nation of volatility, use MPMS Chapter 8.4 in conjunction 3 Definitions with this standard. For sample mixing and handling of sam- ples, refer to MPMS Chapter 8.3. 3.1 automatic sampler: A device used to extract a rep- Petroleum and petroleum products covered in this stan- reientative sample from the liquid flowing ina pipe. The au- dard are considered to be single phase and exhibit Newto- tomatic sampler generally consists of a probe, a sample nian characteristics at the point of sampling. extractor, an associated controller, a flow-measuring device, and a sample receiver.- 3.2 automatic sampling system: A system that consists 2 References of stream conditioning, an automatic sampler, and sample mixing and handling. API 3.3 dissolved water: Water in solution in petroleumand Manual of Petroleum Measurement Standards petroleum products. Chapter 3, “Tank Gauging” 3.4 emulsion: An oil/water mixture that does not readily Chapter 4, “Proving Systems” separate. Chapter 5, “Metering” Chapter 6, “Metering Assemblies” 3.5 entrainedwater: Watersuspendedin oil. Entrained Chapter 8, “Sampling” water includes emulsions but does not include dissolved wa- Chapter 10.9, “Standard Test Method for Water in ter. Crude Oils by Coulometric Karl Fischer 3 6 flowproportionalsample: Asample takenfrom’ a . Titration” pipe suchthat the rate of sampling is proportional, through- Publ 2026 Safe Descent onto Floating Roofs of out the sampling period, to the flow rate of liquid the pipe. in Tanks in Petroleum Service 3 7 free water: Water that exists as a separate phase. . Publ 2217A Guidelinesfor Work in Inert Confined 3.8 grab: The volume sample of extracted a from Spaces in the Petroleum Industry pipeline by a single actuation of the sample extractor. ASTM’ 3 9 homogeneous: Whenaliquidcompositionisthe . D923 SamplingElectrical Insulating Oils same at all points inthe container, tank, or pipeline cross sec- D 1145 Sampling Natural Gas tion. Dl265 Sampling Liquefied Petroleum Gases 3.10 isokineticsampling: Sampling in suchamanner that the linear velocity of the liquid through the opening of ‘American Society for Testing and Materials, 100 Bar Harbor Drive, West the sampling probeis equal to the linear velocity of the liq-- Conshohocken, Pennsylvania 19428. is uid in the pipeline at the sampling location and in the same *Gas Processors Association, 6526 E. 60th Street, Tulsa, Oklahoma 74145. %s.titute of Petroleum, 61 New Cavendish Street, London WIMBAR, direction asthe bulk of the liquid in the pipeline approachingI England. the sampling probe. 1COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 8. API M P M S * 8 * Z 95 m 0732290 0549036 749 m 2 CHAPTER SAMPLING 3.1 1 Newtonianfluid: A liquid whose viscosity is un- 3.29 worstcaseconditions: Theoperatingconditions affected by the kind of magnitude of motion or agitation to for the sampler that represent the most uneven and unstable which it may be subject as long as the temperature remains concentration profile at the sampling location. constant. 3.12 power mixer: A device that uses an external source of power to achievestream conditioning. 4 Significanceand Use 3.1 3 primary sample receiver/container: A vesselinto Representative samples of petroleum and petroleum prod- which all samples are initially collected. ucts are required for the determination of chemical and phys- 3.14 probe: Thatportion ofan automaticsampler that ical properties, which are used to establish standard volumes, extends into the pipe and directs a portionof the fluid to the prices, and compliance with commercial and regulatory sample extractor. specifications. 3.1 5 profile testing: A procedureforsimultaneously 4.1 APPLICABLE FLUIDS sampling at several points across the diameter of a pipe to identify the extent of stratification. This standard is applicable to petroleum and petroleum products with vapor pressure at sampling and sample stor- 3.16 representativesample: Aportion extracted from age temperature less than or equal to 101.32 kilopascals a total volume that contains the constituents in the same pro- (14.7 pounds per square inch absolute). Reference API portions that are present in that total volume. MPMS Chapter 8.4 when sampling for RVP determination. 3.17 sample: Aportionextractedfroma total volume that mayor may not contain the constituents in the same pro- 4.2 NONAPPLICABLE FLUIDS portions that are present in that total volume. Petroleum and petroleum products whose vapor pressure 3.18 samplecontroller: Adevice that governs the op- at samplingandsamplestorageconditionsareabove eration of the sample extractor. 101.32 kilopascals (14.7 pounds per square inch absolute) 3.1 9 sample extractor: A device that removes a sample and liquefied gases (for example, liquefied natural gas, liq- uefied petroleum gas) are not covered by this standard. In (grab) from a pipeline, sample loop, or tank. addition, petroleum asphalts not coveredby this standard. are 3.20 samplehandlingandmixing: Theconditioning, While these methods will produce a representative sam- transferring, and transporting of a sample in a manner that ple of the flowing liquid the sample receiver, specialized into does not compromise the integrity of the sample. sample handling may be necessary to maintain sample in- 3.21 sample loop (fast loop or slip stream): A low vol- tegrity of morevolatile materials at high temperatures or ex- ume bypass diverted from the main pipeline. tendedresidencetimesinthe receiver. Suchhandling requirements are not within the scope of this method. The 3.22 sampling: All the steps required to obtainasam- procedures for sampling these fluids are described in ASTM ple that isrepresentative of the contents of any pipe, tank,or Methods D1265,D923, D l 145, and GPA 2166. other vessel and to place that sample in a container from which a representative test specimen can taken for analy- be sis. 5 RepresentativeSamplingCriteria 3.23 samplingsystemproving: Aprocedureused to validate an automatic sampling system. The followingcriteria must be satisfied to obtain arepre- 3.24 sedimentandwater (SSrW): Material that coex- sentative sample from a flowingstream. ists with, yet is foreign to, a petroleumliquid. S&W may in- a. For nonhomogeneous mixturesof oil and water, free and cludedissolvedwater,freewater,andsediment,and entrained water must be uniformly dispersed at the sample emulsified and entrained water and sediment. point. 3.25 staticmixer: A device that utilizes the kinetic en- b. Grabs must be extracted and collected in a flow propor- ergy of the flowing fluid to achieve streamconditioning. tional manner that provides a representative sample of the entire parcel volume. 3.26 streamcondition: The distribution and dispersion c. Grabs must be a consistent volume. of the pipeline contents, upstream of the sampling location. d. The sample must be maintained in the sample receiver 3.27 stream conditioning: The mixing of aflowing without altering the sample composition. Venting hydro- of ~ stream so that a representative sample may be extracted. carbon vapors during receiver filling and storage mustbe 3.28 timeproportionalsample: Composed of equal minimized. Samples mustbemixedandhandled to ensurea I volume grabs taken from pipeline at uniform time intervals a representative test specimen is delivered into the analytical during the entire transfer. apparatus.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 9. ~ API 1PlSUB.Z 75 0732270 0547037 685 m SECTION 2"STANDARD PRACTICE FOR AUTOMATIC NG OF LIQUID SAMPLI PETROLEUM AND PETROLEUM PRODUCTS 3 ~ 6 AutomaticSamplingSystems a nonrepresentative sample will result. Alow-flow alarm should be installed to alert the operator of a lossof flow. In A typical automatic sampling system consistsof stream no case shall a filter be installed in a sample loop upstream conditioning upstream of the sampling location, a device to of the sample extractor, as it may alter the representativeness physically extract a grab from the flowing stream, a flow of the sample. measurement device for flow proportioning, a means to con- trol the total volume of sample extracted, a sample receiver to collectand store the grabs, depending on the system, and 7 SamplingFrequency a sample receiverhixing system. Unique properties of the petroleum or petroleum product(s) being sampled may re- Guidelines for sampling frequency can be given in terms quire the individual components or the entire system to be of grab per lineal distance pipeline volume. For marine of insulated andor heated. Appendix E references many of the and pipeline service, this minimum guideline can be related design considerations that should be taken into account. to barrels per grab using the following equation: Grabs must be taken in proportion to flow. However, if the flow rate, duringthe total parcel delivery (week, month, bbl/grab = 0.0001233 X D*or 0.079548 X dz etc.) varies less than 2 10 percent from the average flow rate, Where: a representative samplemay be obtained by the time pro- D = nominal pipe diameterin millimeters portional control of the grabs. There are two types automatic sampling systems (see of d = nominal pipe diameter in inches Figure 1). Both systems can produce representative samples This formula equates to one grabfor every 25 lineal me- if properly designed and operated. One system locates the ters (approximately 80 feet)of pipeline volume. extracting device directly in the mainline, whereas the other Sampling frequency should be based on maximizing system locates theextracting device in a sampleloop. grabs for the available receiver size.Typically, lease auto- In a sample loop type system, a probe is located in the matic custody transfer (LACT) or automatic custody trans-- main pipeline and directs a portion of the fluid flow into the fer (ACT) units are paced at one per one to ten barrels. grab sample loop. This probe may be a 90-degree elbow or a 45- The optimum samplingfrequency is themaximum num-- degree bevel facing upstream (see Section 11). The average ber of grabs that may be obtained from any parcel operating flow velocitythrough the sample loop shall be near the max- within the grab frequency and grab volume limitations of the imum average velocity expected in the main pipeline, but not equipment. The completed sample shouldbe of sufficient less than 2.5 minutes per second (8 feet per second). volume to mix and properly analyze while notoverfilling the The controller that operates the sample extractor in the sample receiver. sample loop receives itsflow proportional signal from the Sampling of small line fill volumes, usually associated flow meter(s) in the main line. For sample loop installations, with marine applications, requires increasing the grab fre- a flow indicator must also be installed in the sample loop.If quency to permit collection of sufficient sample volume to circulation in the sample loop stops and sampling continues, run only those analytical tests deemed most critical. Sample grab discharge Ifin downward " C I sloping line) Sample grab discharge Probe (in downward Sample receiver , sloping line) (insulate and heat Flow Sample receiver (insulate and heat """ signal J -- if necessary) ---Flow signal Sample extractor Sample and probe extractor Flow indicator Automatic Sampling-in-Line Automatic Sampling With a Fast Loop Note: Arrow does not indicate piping orientation. Figure 1-Typical Automatic Sampling SystemsCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 10. 4 CHAPTER 8”SAMPLINGI 8 Stream Conditioning ditional stream conditioning unless specifically sampling for water content or where the sampler is downstream of a 8.1 GENERAL blending manifold. The sampler probemust be located at a point in the pipe where the flowing stream is properly conditioned. This con- 9 Special Considerations for Marine ditioning may be accomplished with adequate flow velocity Applications through the piping system, mixing elements may be added or tosupplementmixingprovided by thebasicpiping. When pumping from shore orvessel tanks, a significant Petroleum that contains free orentrained sediment and water amount of free water may be transferred during short peri- (S&W) requires adequate mixing energyto create a homo- ods of time (see Appendix C). This usually occurs on the geneous mixtureat the sample point. commencement of pumping when the flow rate is low and Petroleum productsare generally homogeneousand usu- , the oil/water mixture is stratified. If the method of stream ally require no special stream conditioning. Exceptions to conditioning is not adequate duringthis period of low flow, this may occur if free water is present orif a productis exit- tanks that do not contain free water should be used.Tanks ing a blending system. containing free water can be pumped whenthe pumping rate has reached normal. 8.2 VELOCITIES AND MIXING ELEMENTS If the sampler is located some distance from point of the load/discharge, operating procedures should account the for Table 1, based ontests, provides a guidelinefor minimum line fill between those two points. velocities versus mixing elements for pipes 5 centimeters (2 inches) in diameter and larger. Stream conditioning can be accomplished with pressure reducing valves, metering 10 ProbeLocation and Installation manifolds, lengths of reduced diameterpiping, or piping el- ements (valves, elbows, tees, piping, or expansion loops). The recommended sampling area is approximately the If the flow velocity at the automatic samplerprobe loca- center half of thepipeline diameter shown in Figure 2. tion falls below the minimum levels detailed in Table l, ad- ditional means, such as power mixers or static mixers, will 10.1 The probe opening must face upstream and the ex- be required to provide adequate stream conditioning . The ternal body of the probe should be marked withthe direction effect of viscosity, density, and water content, as well as the of flow to verify that the probe is installed correctly. relative position of the mixing element(s) and sample probe 10.2 The probe must be located in a zone where sufficient should also be considered. mixing results in adequate streamconditioning. This zoneis Specific calculation procedures for estimating the ac- generally from three to ten diameters downstreamof piping ceptability of a proposed or existing sampling location are elements, 0.5 to 4 diameters fromstatic mixers, and three to detailed in Appendix B. ten diameters from power mixers. When or power mix- static Again, remember that petroleum products assumed to are ers are used, the manufacturer of the device shouldbe con- be homogeneous at the point of sampling andrequire no ad- sulted for the probe’s optimum location. Table 1“General Guidelines for Minimum Velocities Versus Mixing Elements Minimum Pipeline Velocity, meters per second Mixing Piping Element O 0.305 0.61 0.9 I 1.22 1.52 1.83 2.13 2.44 Power mixing Horizontal or vertical Adequate at any velocity Not Static mixing Vertical Stratified predictable Adequately dispersed Static Horizontal mixing Stratified Not predictable Adequately dispersed Vertical Stratified Piping elements Not predictable Adequately dispersed Piping elements Horizontal Stratified Not predictable Adequately dispersedI None Horizontal or vertical Stratified O or not predictable 1 2 3 4 5 6 7 8 Minimum Pipeline Velocity, feet per secondCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 11. SECTION 2"STANDARD PRACTICE FOR AUTOMATIC SAMPLING OF LIOUID PETROLEUM AND PETROLEUM PRODUCTS 5 11.2 Probe designs commonly used are described as fol- lows: 1. A closed-end probe equipped with an open orifice. (See Figure 4A.) 0.250 2. A short-radius elbow or pipe bend facing upstream. The end of the probe should be chamfered on inside diameter the Recommended region to give a sharpentrance. (See Figure4B.) for samplingpoint / 3. A tube cut at a 45-degree anglewith the angle facing up- stream. (See Figure 4C.) Figure 2-Recommended Sampling Area 12 Extractor An automatic sampleextractor is a devicethat extracts a sample (grab) from the flowing medium.The extractor need 10.3 The holdup volume in the probe and extractor should not be an integral part of the probe. The sample extractor be minimized.The line from the outlet the extractor to the of shouldextractaconsistentvolume that isrepeatable sample receiver must continuously slope downward from the within 3 percent over the range operating conditions and of extractor to the receiver and contain no dead space. sampling rates. 10.4 The preferred installation of acombinedprobe- extractor is in the horizontal plane. 10.5 If a vertical piping loop is used for stream condition- 13 Controller ing, locate the probe in the downflow section of the loop to A sample controlleris a device that governs the operation- obtain the benefit of theadditional stream conditioning vided by the three 90-degree elbows. Locate the probe pro- a min- of the sample extractor. The sample controller should permit- imum of three diameters pipe downstream of the top the selection of the sampling frequency. 90-degree elbow and not closer than half pipe diameterup- stream of the final exiting elbow. (See Figure3.) 14 Sampler Pacing 10.6 According to tests sponsored by the API, locating a sample probe downstream of a single 90-degree bend is not 14.1CUSTODYTRANSFER METERS recommended because of inadequate stream conditioning. Custody transfer meters shouldbe used to pace the sam- pler where available. When flow is measured by multiple 11 Probe Design meters, the sampler should be paced by the combined total flow signal. Alternatively, a separate sampler may be in- 11.1 The mechanical design of the probe should be com- stalled in each meter run. The sample from each meter run patible with the operating conditionsof the pipeline and the must be considered part of the total sample and in the same a fluid being sampled. Thereare three basic designs shown in proportion as that meters volume is tothe total volume. Figure 4. Probe openingsshould be inthe center half of the pipe diameter. 14.2SPECIAL FLOW METERS When custody transfer is by tank measurements, a flow signal must be provided to the sample controller. This signal may be provided by an add-on flow metering device. These devices should have an accuracy of 2 10 percent or better, over the total volume of the parcel. 14.3TIMEPROPORTIONALSAMPLING An automatic sampler shouldpreferably operate in pro- portion to flow. However, sampling in a time proportional mode is acceptable if the flow rate variation less than -+ 10 is Figure 3-General Vertical Piping Loop Configuration percent of the average rate over the entire parcel.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 12. A P I MPMS*8.2 95 m 0732290 0549020 L 7 T m 6 CHAPTER 8"SAMPLING End of probe closed orifice facing upstream Manufacturers 45" Bevel A B C Figure +Probe Designs 15 PrimarySampleReceivers j. Use of multiple sample receivers should be considered to allow flexibility in sampling sequential parcels and linedis- A sample receiverkontaineris required to hold and main- placements. Care must be taken in the piping design to pre- tain the composition of the sample in liquid form. This in- vent contamination between samplesof different parcels. cludes bothstationary and portable receivers, either of which See Figure 5. may be of variable- or fixed-volume design. If theloss of va- k. Receivers should have an inspection cover or closure of pors will significantly affect the analysis of the sample, a sufficient size to facilitate easy inspection and cleaning. variable-volume type receiver should be considered. Mate- 1. Facilities for security sealing should be provided. rials of construction should compatible the be with m.Thesystemmust be capable of completely draining the - petroleum or petroleum product sampled. receiver, mixing pump, andassociated piping. - n. The circulating system shall not contain any dead legs. 15.1 STATIONARY RECEIVERS General design features (thesefeatures may not be appli- cable to some types of receivers, for example, variable- volume receivers): Probe or extractor a. Receiver design must allow for preparation of a homoge- neous mixture of the sample. Minimize b. The bottom of the receiver must be continuously sloped manifold size downward toward the drain to facilitate complete liquid and length withdrawal. There should be no internal pocketsor dead Solenoid spots. valves c. Internal surfaces of the receiver should be designed to minimize corrosion, encrustation, and clingage. d. A means should be provided to monitor filling of the re- ceiver. If a sight glass is used, it must be easy to clean and not be a water trap. e. A relief valve should be provided and set at a pressure that does not exceed the design pressure of the receiver. f. A means to break vacuum should be provided to permit Single Multiple receiver receivers sample withdrawal from the receiver. g. A pressure gauge should be provided. h. Receivers should be sheltered from adverse ambient con- ditions when in use. Note: 6.4 or 9.5 millimeter (/4" or 3/~")tubing, as short as possible i. Receivers may need to be heat traced and/or insulated and sloping continouslytoward the sample receiver, shouldbe used. 9.5 millimeter (three-eighths inch) tubing should used where long be whenhighpourpointorhighviscositypetroleumor sampling lines cannot avoided or in crude oil service. be Heat trace petroleum products are sampled. Alternatively, they may be and insulate these lines when necessary. housed in heated and insulated housing. Caution should be taken to ensure added heating does not affect the sample. Figure 5-Stationary Receiver(s) InstallationCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 13. ~ A P I MPMS*8-2 75 m 0732270 0547023 006 W SECTION 2”sTANDARD PRACTICE FOR AUTOMATICSAh4PLING OF LIQUID PETROLEUM AND PETROLEUM PRODUCTS 7 3-way ball valve- hand or motor Note 1 operated from control room Probe or extractor Quick Quick disconnect receiver receiver (Note 2) (Note 2) Notes: 1. Tubing 6.4- 9.5-millimeter (one-quarter-inch V,-inch), as short as or or possible and sloping continuouslytoward the sample receiver, should be used. Three-eighths-inch tubing should be considered wherelong sam- pling lines cannot be avoided or the crude oil is viscous. Heat trace and insulate these lineswhen necessary. 2. Sample should flow into a connection at topof the container. the 3. In warm climates asun shield shouldbe provided to avoid excessive temperature changes in sample receivers. 4. In cold climates, consider placing sample receivers a heatedhousing in or heat trace and insulate the receivers andsample Lies. Figure 6-Portable Receiver(s) Installation 15.2 PORTABLE RECEIVERS outlined in 15.1,portable re- In addition to considerations ceivers may includethe following additional features: a. Lightweight. Figure 7-Typical Portable Marine Installation b. Quick-release connections foreasy connection to anddis- connection from the probelextractor and the laboratory mixer. (See Figure6.) c. Carrying handles. 17 Portable Samplers 15.3 RECEIVER SIZE A typical application of portable samplingsystem is on- a be The receiver should sized to match its intended use and board a marine vessel.There are also occasionalapplications operating conditions. The size of the receiver is determined on shore. The same criteria for representative sampling ap- by the total volume of sample required, the number of grabs plies to both portable and stationarysampling systems. Cau- required, the volume of each grab, and the transportability tion shouldbe taken when using portable samplers on marine of the receiver if portable. vessels due to the difficulty in verifyingstream conditioning Typical sample receiver sizes are: during actual operations. An example of a marine applica- Lease automatic custody transfer 1G60 liters (3-15 gallons) tion is shown in Figure 7. Pipelines (crude petroleum) 20-60 liters (5-15 gallons) Pipelies (products) 4-20 liters (1-5 gallons) 17.1 DESIGN FEATURES Portable 1-20 liters (1 quart-5 gallons) Tanker loadingtunloading 20-75 liters (5-20 gallons) Special features and installation requirements for a Line fill (marine applications) Volume required for critical tests portable sampler are the following: a. A spool assembly fitted with a sample probe/extractor 16 SampleMixingandHandling and flow sensor is inserted between the ship’smanifold and each loading/unloading r or hose. If the grab size of each am Transfer of samplesfrom the receiver to another container sampler isequal, a common receiver can be used. or the analytical glassware in which they will be analyzed b. A controller is required for each extractor. The controller requires special care to maintain their representative nature. must be able to record total number of grabs and total See API MPMS Chapter 8.3 for detailed procedures. The volume. sample in the receiver must be properly mixed to ensure a c. Piping arrangementat the ship’smanifold will often dis- homogeneous sample before any transfer. tort the flow profile. The flow sensor, when operated underCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 14. A P I MPMSUB.2 95 0732290 0549022 T 4 2 8 CHAPTER 8”SAMPLING the piping and flow conditions at the ship’s manifold, must 18 AcceptanceTests meet the accuracy criteria in 14.2. d. Stream conditioning is accomplished by velocity of the 18.1 GENERAL fluid and the pipingelements aheadof the probe. The num- ber of hoses, arms, and lines in service at any one time may Testing is recommended to confirm that a sampling sys- need to be limited to maintain sufficiently high velocity. tem is performingaccurately. Appendix Aoutlines methods e. The controller may be placed on the ship’s deck, which for testing samplers that are used for the collection of S&W is usually classified as a hazardous area. If the controller is or free water samples. The test methods fall in two general electronic, it should meet the requirements of the hazardous categories: total system testing and component testing. area. f. Air supply must meet therequirements of the equipment. 18.2 TOTAL SYSTEMTESTING g. For high pour or viscous fluids, particularly in cold cli- This test method is a volume balance test where tests are mates, the line from the extractorto the receiver may require conducted for known amounts of water. Itis designed to test a thermally insulated high-pressure hose or tubing. The re- the total system including the laboratory handlingand mix- ceiver should be placed as close to the extractor as possible ing of sample. Two procedures are outlined. One involves to minimize the hose length. The hose or tubing shouldhave only the sampler under test, the other utilizes an additional an internal diameter of 9.5 millimeters (3/8 inch) or more and sampler to measure the baseline water. slope continuously downward fromthe extractor to the re- ceiver. The line from the extractor the receiver may require to 18.3 COMPONENT TESTING heat tracing. h. Filling of receivers should be monitored to ensure that This test method involves testing individually the com- each sampler is operating properly. Frequent visual inspec- ponents that comprise a sampling system. Where applicable, tion, level indicators, and weighing have proven to be ac- some of the component tests may be conducted prior to in- ceptable monitoring methods. stallation of the total system. Component tests include i. The portable sampler is used intermittently: therefore the probe/extractor, profile (for stream conditioning), special sample probe, extractor, and flow sensor should be cleaned flow meter, and primary samplereceiver and mixer. after every use to prevent plugging. If a system design has been proven testing, subsequent by j. All components and installation must meet applicable systems of the same design (for example, LACT units), in- regulations, such as those of the U.S. Coast Guard. cluding piping configuration, and operated under the same or less criteria1 conditions (for example, higher flow rate, 17.2 OPERATINGCONSIDERATIONS higher viscosity, lower water content) need not be tested. The portable sampler operator must maintain operating Once a system or system design has been proven, the fol- conditions that provide adequate mixing and produce a rep- lowing checks canbe used to confirm system reliability: resentative sample. Performance criteria is given in Ap- a.Streamconditioning:Flowrateorpressuredrop if pendix G, Performance Criteria for Portable Sampling Units. equipped with power or static mixer. To meet the criteria requires cooperation of the vessel crew b. Profile test for systems with only piping elements. and shore personnel. Special operating requirementsare: c. Pacing device: Compare recorded batch volume known to 1. The portable sampler operator should keep flow rate the volume. at each flow sensing devicewithin its design rangeby limit- d. Compare actual sample volumeto expected volume. ing the number of loading lines or hoses in service during e. Extractor: Compare actual sample volume to expected periods of low flow rates, such as start-up, topping off, and volume. stripping. f. Compare actual grab size to expected grab size. 2. For discharge operations, the vessel compartment dis- Portable sampling systems canbe tested by the compo- charge sequence must be controlled so that the amount of nent testing method except for proper streamconditioning. free water being discharged during the start-up operation is less than 10 percent of the total amount water inthe cargo. of 18.4 REQUIREMENTS FOR ACCEPTABILITY 3. For loadings, a shoretank with no free water is preferred for the initial pumping. Water drawing tank andor pump- the Testing by either the component or total system method ing a small portion ofthe tank to another shore tank prior to requires that two of three consecutive sets of test data re- out the opening tank gaugeare suggested. peat within the tolerance stated for the test.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 15. SECTION 2”STANDARD PRACTICE FOR AUTOMATIC SAMPLING OF LIQUIDPETROLEUM AND PETROLEUM PRODUCTS 9 19 OperationalPerformanceChecks/ Several procedures may be used to accomplish this re- Reports quirement, such as sight glasses, gauges,or weigh cells. Se- lection of a procedure should be based on (a) volume of transfer, (b) type of installation, (c) time intervalof transfer, Monitoring of sampler performance is a necessary part of (d) whether the sampling facility is manned, (e) receiver every sampling operation. Monitoring is required to make type, ( f ) purpose of the sample, and (g) equipment used. sure that thesample extractor is extracting a uniform grab in For LACT and ACT units, monitoring may consist of a flow proportional manner, This is normally accomplished comparison between sample volume collected and expected by assessing the sample volume collected to ensure that it sample volume. For very large transfers, including marine meets expectations for the equipment and transfer volume transfers, more information may be desired as outlined in involved. Appendixes F and G.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 16. A PM P M S * 8 * 2 I 95 m 0732290 0549024 815 m APPENDIX A-ACCEPTANCE METHODOLOGIES FOR SAMPLING SYSTEMS AND COMPONENTS A.l Acceptance Testing-Water been tested, the receiver and mixer must be tested prior to Injection Volume Balance Tests the acceptance test in accordance with Appendix B of API MPMS Chapter 8.3 using the oil and volume that are to be A.l.l GENERAL sampled. 2. Determine the method and accuracy by which the water This appendix describes three test methods shown to be and oil volumes will be measured. Water injection meters acceptable in proving the performance of pipeline and ma- should be installed and proven in accordance with API rine automatic pipeline sampling systems: single sampler, MPMS Chapters 4, 5 , and 6 . Oil volumes should be mea- dual sampler, and component testing. These methods have sured by tankgauge or meter in accordance with applicable equal validity and theorder listed should not be construed as API MPMS Chapters 3,4, 5 , and 6 guidelines. one method having preference over another. Once a system 3. Locate the water injection point upstream the elements of design has been proven, subsequent systems the same de- of expected to produce the stream conditioning for the sam- sign (for example, LACT units), including piping configura- pling system. Be aware of potential traps in the piping that tion and similar service, need not be tested. Refer to Section may prevent all of the injected water from passing the sam- 18 for verification of systems of the same design. ple point. Care should be taken to ensure that the location The following procedures are presented for the testing of and manner in which water is injected does not contribute systems to identify water in petroleum. The same approach additional mixing energy at the point of sampling, which may be modified to apply to petroleum blending systems. would distort the results. Equipment or facilities used to test The single and dualsampler tests are designed to test the inject water should be inaccordance with local safety prac- entire sampling system starting with the stream condition in tices. the pipeline through collection and analysis of the sample. 4. Review the normal operating conditions of the pipeline in These are volume balance tests in which a known amount of terms of flow rates and crude types. Select the most com- water is injected into a known volume of oil of a known mon, worst case conditions to test the sampling system. The baseline water content. As these volumes pass the sampler worst case is commonly the lowest normal flow rate and the under test, a sample is collectedand the results analyzed for lowest relative density (highest API) gravitycrude normally comparison against the known baseline water plus injected received or delivered. water. 5. In the case of the single sampler acceptance test, a source The single sampler test requires that an assumption be of constant water content for oil must be identified for the made concerning the baseline water content during time the test. It is suggested that this oil be isolated, if possible, be- that test water is injected. Successful tests are dependent on cause changes in the baseline water content can produce in- a constant baseline oil throughout the test. If a constant base- conclusive test results. line oil cannot be ensured, inconclusive results will be ob- tained. A.1.2 SINGLE SAMPLER-ACCEPTANCE TEST In the dual sampler test, the first sampler (baseline sam- pler) is usedto measure the baseline water content during the The following are the singlesampler-acceptance test test. Test water is injected between the baseline and primary procedures: samplers. The primary sampler (the one under test) is used 1. Purge the system at a sufficiently high flow rate to dis- to collect the baseline plus injected water sample. It is not place free water that may be lying in the pipeline system up- necessary for the two sampling installations to beof identi- stream of the automatic sampling system. (Refer to cal or similar design. Figure A-1.) Preparation prior to the acceptance test should include the 2. Establish the flow rate for the test. following procedures: 3. Collect the first baseline sample(s). A baseline sample 1. Test the sample receiver and mixer as outlined in API may be a composite sample collected in a separate sample MPMS Chapter 8.3, Appendix B. During the sampler ac- receiver or several spot samples collected at intervals directly ceptance test, water injection should last at least one hour. from the sample extractor. The corresponding sample volume collected during a sam- 4. Record the initial oil volume by tank gauge meter read- or pler acceptance test is usually less than the volume expected ing. Simultaneously begin collectinggrabs in the samplere- under normal conditions.Therefore, if the sample volume to ceiver. be collected during the sampler acceptance test is less than 5. Record the initial water meter reading; turn the water on the minimum volume at which the receiver and mixer have and adjust the injectionrate. 11COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 17. API M P M S * 8 - 2 95 m 0732290 0549025 751 m 12 CHAPTER SAMPLING Purge I 1 Baseline sample b ._ To allow for lag > ._ Water arrives c ad ,n spreading ä , Y Test sample I Baseline sample I Test Note: Times are calculated based on minimum oil flow rate and the distance between the injection and the sample point. Figure A-1"Sequence of Acceptance TestActivities 6. A minimum of one hour is recommended for the water in- V = volume of injected water in barrels jection. Winj = water injected during test (vol %) 7. Turn the water off and recordthe water meter reading. 8. Continue sampling into thereceiver until the injectedwa- - - v x 100 ter is calculated to have passed the sampler. TOV 9. Stop the collection of the test sample and simultaneously 14. Repeat Steps 3 through 13 until two consecutive tests record the oil volume by tank gauge or meter reading. that meet the criteria in A. 1.4.1 have been obtained. 10. Collect the second baseline sample(s). Note: When.firoduction water is used, makecorrection for dissolved solids 11, Analyze the baseline samples. as applicable. 12. Analyze the test sample. 13. Using the following equation, calculate the deviation A.1.3DUALSAMPLER-PROVINGTEST between the water in the test sample minus the water in the The dual sampler test is a two-part test. In the first part, baseline, corrected to test conditions, compared to the the two samplers are compared to one another at the base- amount of water injected. line water content. In part two of the test, water is injected between the two samplersto determine if the baseline water = <wt,g - - winj plus injected water is detected the primary sampler. Refer by Where: to Appendix I, Sampler Acceptance Test Data Sheet. DEV = deviation (vol %) A.1.3.1 Part 1: BaselineTest Wte, = water in test sample (vol %) 1. Purge system to remove free water. Wb, = baseline water adjustedto test condi- 2. Establish steady flow in line. tions (vol %) 3. Start baseline sampler. Record tank gauge or meter read- ing. 4. Start primary sampler after pipeline volume between samplers hasbeen displaced. Wavg = average measured baseline water 5 . Stop baseline sampler after collecting targeted sample (vol %) volume. A minimum of one hour is recommended. Record TOV = total observed volume (test oil plus tank gauge or meter reading. injected water) that passes the sampler 6. Stop primary sampler after pipeline volume between (barrels) baseline and primary samplers has been displaced.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 18. A P I M P M S * 8 = 2 9 5 W 0732270 0549026 698 m SECTION 2”sTANDARD PRACTICE FOR AUTOMATIC SAMPLING OF LIQUIDPETROLEUM AND PETROLEUM PRODUCTS 13 7. Analyze test samples. Table A-1-Allowable Deviations for the Single and 8. Compare results and make sure they are within accept- Dual Sampler WaterInjection Acceptance Tests able tolerance as per Table A-1 before proceeding. (Volume Percent) Allowable Deviations A.1.3.2 Part 2: Water Injection Test Total Water (Wb, + W ,”,) Using Tank Gauges Using Meters 9. Record water meter reading. 0.09 0.5 0.13 10. Start baseline sampler, inject water, and record tank 1.o 0.15 0.1 1 gauge or meter reading all in rapid succession. 1.5 0.16 0.12 1 l. Start primary sampler immediately priorto arrival of in- 2.0 0.17 0.13 jected water. 2.5 0.18 O. I4 12. Collect targeted sample volume with baseline sampler. 3.0 0.19 0.15 13. Stop baseline sampler, record tank gauge or meter read- 3.5 0.20 O. I6 ing, and shut off water injection all in rapid succession. 4.0 0.21 O. 17 14. Record water meter reading. 4.5 0.22 0.18 15. Stop primary sampler after displacement of pipeline volume between baseline and primary samplers. 5.0 0.23 0.19 16. Analyze test samples. Notes: 17. Repeat Steps 2 through 14 until two consecutive tests that meet the criteria inA. 1.4.2 have been obtained for both 1. The reference to tanks or meters refers to the method used to determine the volume of crude oil or petroleum in the test. parts of the test. 2. Deviations shown reflect use of the Karl Fischer test method described in MPMS Chapter 10.9 for water. A.1.4 APPROVAL FOR CUSTODY TRANSFER 3. Interpolation is acceptable for water concentrations between values shown in the table. For example, iï the total water is 2.25 percent, the al- The acceptance test is valid and the automatic sampling lowable deviation using tank gauges would be 0.175 percent, and 0.135 per- system is acceptablefor custody transfer if two consecutive cent if using meters. test runs meet the following criteria: 4. This table is based, in part, on statistical analysis of a database consisting of 36 test runs from 19 installations. Due to the number of data, it was not possible to create separate databases for analysis basis the method of vol- A.1.4.1 SingleSamplerTest ume determination (by tank or meter). Therefore, it was necessary to treat the data as a whole for analysis. The database is valid for the water range a. The difference in the percent water in the beginning and 0.5 percent to 2.0 percent. ending baselines is O. 1 percent or less. The reproducibility standard deviation calculated basis the data, at a 95 b. The deviation between the test samples and the known percent confidence level, has been used ïor the meter values shown in the table in the water range 0.5 percent to 2.0 percent. Assigning these values to baseline plus injected water is within the limits shown in the meter is based on a model that was developed to predict standard devi- Table A- l. ations ïor volume determinations by tanks and meters. Values shown in the table for the tank, in the range 0.5 percent to 2.0 percent, were obtained by adding 0.04 percent to the meter values in this water range. The value of A.1.4.2DualSamplerTest 0.04 percent was derived from the aforementioned model as the average bias between tank and meter volume determinations. a. The difference between the two samplers during the base- As there is insufficient test data for water levels over 2.0 percent, values line test must be within 0.1 percent. shown in the table above 2.0 percent have been extrapolated on a straight b. The difference between the second sampler (test sampler) line basis using the data in the 0.5 percent to 2.0 percent range. and the baseline sampler plus injected water must be within In order to develop a broader database, owners of systems are encour- aged to forward a copy of test data using test data sheets as shown in Ap- the limits shown in Table A-l. pendix I to the API, c/o Industry Services Department, 1220 L Street, N.W., Washington, D.C. 20005. Confidentiality is ensured. A.1.5 PROCEDURESTO FOLLOW IFTHE ACCEPTANCE TEST FAILS l . Ensure volume of oil was calculated and recorded cor- A.2 ComponentPerformanceTest rectly. 2. Ensure volume of water was calculated and recorded cor- A.2.1PROFILE TESTTO DETERMINESTREAM rectly. Ensure scaling factor is correct and/or the meter fac- CONDITION tor has been appliedto obtain correct volume. The extent of stratification or nonuniformity of concen- 3. If inadequate stream conditioning in the pipeline is sus- tration can be determined by taking and analyzing samples pected, validate the sample point by one of the following: simultaneously at several points across the diameter of the a. Appendix B to estimate the water-in-oil dispersion. pipe. The multipoint probe shown in Figure A-2 an exam- is b. A multipoint profile test as described in A.2.1.2.1. ple of a profile probe design. This test should be conductedCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 19. A P I MPMS+B*2 95 m 07322900549027524 m 14 SAMPLING CHAPTER in the same cross sectionof pipe where the sample probe A.2.1.2.3 Probe Orientation will be installed. Profiles in horizontal lines must be taken vertically, A.2.1.1 Criteria for Uniform Dispersion and whereas profiles in vertical lines should betaken horizon- Distribution tally. A minimum of five profile tests must meetthe criteriain A.2.1.2.4 Conditions Test A.2.1.4. three of those profiles indicate stratification, the If mixing in the line is not adequate. The test should be set upto measure the worst-case con- ditions, including the minimum flow rate and lowest flow A.2.1.2ProfileTestRequirements viscosity and density or other conditions as agreed upon. A.2.1.2.1 Profile Probe A.2.1.2.5 Water Injection A probe with a minimum of five sample points is recom- mended for 30-centimeter (12-inch) pipe or larger. Below The water injection method described in testing automatic 30-centimeter (12-inch) pipe size, three sample points are sampling systems (Section 18) is recommended. adequate. A.2.1.2.6 Sampling A.2.1.2.2 Sampling Frequency Sampling should begin two minutes before the calculated Profile samples should not be taken more frequently than water arrival time and continue until least ten profiles have at at two-minute intervals. been taken. I. I Collection f " , 3/4 point - f I4point r 1" from wall C tubes Needle valves Toggle-type o L "" &shut-off valves - _I_ - . 3 - - _I_ - - 1/4" probe Midpoint end Siver solder to of lu Probe body probe body Notes: 1. For pipes less than 12 inches, delete the I/, and 3/4 points. 2. The punch mark on probe sleeve identifies the direction of probe openings. 3. When the probe is fully inserted, take up the slack in the safety chains and secure the chains tightly. 4. The probe is retractable and is shown in that position. Figure AQ-Multipoint Probe for Profile TestingCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 20. A P I MPMS*8*2 75 0732290 0549028 460 m SECTION 2"STANDARD PRACTICE FOR AUTOMATIC SAMPLING OF LIQUID PETROLEUM AND PETROLEUM PRODUCTS 15 Table A-2-Typical Profile Test Data, A.2.1.4ApplicationofDispersionCriteria in Percent Volumeof Water Table A-2 lists data accumulated during a typical profile Point (8Volume - Water) test. Units are percent volume of water detected. Approxi- A B C D E mately 1,000 barrels of seawater were added to a center Profile Bottom 1/4 Point Midpoint 3/4 Point Top compartment of a 76,000 dead weight ton crude oil tanker. 1 0.185 0.096 0.094 0.096 0.096 The quantity of water was verified by water cut measure- 2 0.094 0.182 O. I35 0.135 0.135 ments shortly before the loading operation. 3 13.46 13.72 13.21 12.50 12.26 To apply the dispersion criteria, it is best to eliminate all 4 8.49 7.84 8.65 8.65 8.33 profiles with less than percent water and the profile taken 0.5 5 6.60 7.69 7.69 6.60 8.00 in the leading edge of the water (whichoccurs in profile 3 of 6 6.73 7.02 6.48 6.73 5.38 Table A-2). Typically, a profile of the leading edgeis erratic with respect to water dispersion. While it is a useful means 7 7.88 6.73 6.73 7.27 5.96 of verifying arrival time, it hinders evaluation of profile data 8 2.78 3.40 3.27 3.08 2.88 and can cause an unnecessarily reduced profile test rating. 9 1.15 1.35 1.54 1.48 1.32 Calculate the point average and deviation for all other pro- 10 0.58 0.40 0.48 0.55 0.47 files with l percent or more water. (See Table A-3.) A.2.1.5 Water Profile Test Procedures Note: Probe installation and operation are covered in A.2.1.6. As a safety precaution, the probe should be installed and removed during low-pressure Refer to Figure A-2 while followingthe steps of this pro- conditions. However, the probe should be equipped with safety chains and cedure. stops to prevent blowout should it be necessary to remove it during opera- tion conditions. 1. Install profile probe in line. Check that the probe is prop- erly positioned and safely secured. A.2.1.3 Description of Terms Specific to This 2. Position a slop can under the needle valves. Open the Method shut-off and needle valves and purge the probes for minute 1 The following definitions are included as an aid in using (or sufficient time to purge ten times the volume in the probe Tables A-2 and A-3 for profile test data and point averages line). and deviation: 3. Adjust needle valves so that all sample containers fill at equal rates. A profile consists of multipoint samples taken simultane- 4. Close shut-off valves. ously across a diameter of the pipe. 5. Open the shut-off valves, purge the probe lines, and A point is a single sample in a profile. quickly position the fivesample containers under the needle The point average is the average of the same point from valves. Close shut-offvalves. all profiles (excluding profiles with than 1.O percent wa- less 6. Repeat Step 5 at intervals of not less than 2 minutes until ter). a minimum of ten profiles have beenobtained. The overallprofile average is the average of all point av- erages. A.2.2SAMPLE PROBUEXTRACTORTEST The minimumflow rate is the lowest operating flow rate, excluding those rates that occur infrequently (that is, one of The grab size should be repeatable within 2 5 percent ten cargoes) orfor short time periods (less than 5 minutes). over the range of operating conditions. Operating parame- Table A-3-Calculation of Point Averages and Deviation Point (% Volume - Water) A B C D E Average % Average of profiles 4 through 9 5.61 5.67 5.73 5.64 5.31 5.59 Deviation from overall profile average" +O.OZ +O.08 +0.14 +0.05 -0.28 (8water) Allowable deviationb (5.59 X 0.05)%Water = ?0.28% Water a The system is rated with respect to the worst point average in the test: point average E has the largest deviation (-0.28). For representative sampling, the allowable deviation is 0.05 percent water for each 1 percent water in the over- all profile average. In this example, the allowable deviation is given by the (5.59 X 0.05)% W = 20.28% W.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 21. A P I NPMS*8*2 95 W 0732290 0549029 3 T 7 m 16 CHAPTER 8"SAMPLING ters that may affect grab size are oil viscosity, line pressure, Special types of meters, such as those described in 14.2, grab frequency, and backpressure onthe extractor. can be verified by comparing the meter pacingthe extractor Test the sample probe/extractorby collecting 100 grabs with tank gauges or custody transfer meters. Conditions for in a graduated cylinder andcalculating the average grab size. the test are: Perform the test at the highest and the lowest oil viscosity, l . The test should be conducted at the average flow rate ex- pressure, and grab frequency. perienced during normal operations. The average grab size will determine if the target number 2. The flow meter must be tested in its normal, operating lo- of grabs will fill the sample receiver above the proper level. cation to determine if piping configuration affects its accu- The average grab size is also used in determining the sam- racy. pler performance (see Appendixes F and G). 3. When using tank gauges as a reference volume, the tank level changes must be large enough to give accurate volume A.2.3 SPECIAL FLOW METER TEST readings. Flow meters used for pacing sample extractors should be If custody transfer meters are used,verification of the within ? 10 percent of the volume measured by tank gaug- flow meter calibration is not necessary. ing or custody transfer meters.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 22. APPENDIX B-THEORETICAL CALCULATIONS FOR SELECTING THE SAMPLER PROBE LOCATION B.l Introduction Symbols Used in Appendix B Symbol Term Units This appendix describes calculation procedures for esti- C Water concentration (waterloil ratio) Dimensionless mating thedispersion of water-in-oil at a sampling location. These procedures have a very simple theoretical base with D Pipe diameter m many of the equations not being strictly applicable; there- d Droplet diameter m fore, they should be used with extreme caution in any prac- E Rate of energy dissipation Wkg ticalapplication. A conservativeapproachisstrongly Eo Energy dissipation in straight pipe Wkg recommended when estimating the acceptable limits for äd- E, Required energy dissipation equate dispersion (stream conditioning). G Parameter, defined in B.2 Dimensionless The equations contained in this appendix have been K Resistance coefficient Dimensionless shown to be valid for large numberof field data. The range a n Number of bends Dimensionless of the field data covered the following correlating parame- PP Pressure drop Pa( 1) ters: Q Volumetric flow rate m3/s Relative density 0.89274.8550 (27"-34 API) r Bend radius m Pipe diameter 40 cm-130 cm (16 in-52 in) Viscosity (cSt @ 100°F) 6-25 cSt @ 40°C V Flow velocity m/S Flowing velocity > 0-3.7 m / s (> 0-12 fusee) Flow nozzle exit velocity Water concentration (%) < 5% 7 d S W Settling rate of water droplets d S Use caution whenextrapolating outside of these ranges. Ax Dissipation distance m When evaluating if dispersion is adequate or not in a Parameter, defined in B.3.2 Dimensionless ß given system, it is recommended to use the worst-case con- Y Ratio between small and large diameters Dimensionless ditions. e Eddy diffusivity m2/s When calculating the dispersion rate E in B.3, it should 8 Turn angle Degrees be noted that dispersion energies different piping elements of are not additive in regard dispersion; for example, when a to V Kinematic viscosity at line temperature m% (2) series of elements is present,the element that should be con- U Surface tension N/m (3) sidered is the one thatdissipates energy the most. P Crude oil density at line temperature kg/m3 As an aid in determining the element most likely to pro- Pd Water density at line temperature kg/m3 vide adequate dispersion, TableB- l has been developed. 4 Flow nozzle diameter m When using Table B-1, it is important to consider it as a guide only and that particular attention should be paid to the Notes: notes. Table B-1 does not preclude the need for a more de- ( I ) 1 Pa = bar tailed analysis of these elements, within a given system, (2) 1 m/s = IO6 cSt = IO6 mm% shown by the tabletobethemosteffective.(See IP (3) 1 N/m = lo3 dydcm Petroleum Measurement Manlml, Part IV, Section 2.) a. The degree of dispersion in horizontal pipes can be esti- 8.2 Dispersion Factors by: mated C c*= I exp ( ) 5 EID As a measureof dispersion, the ratio of water concentra- Where: tion at thetop of a horizontal pipe, C,, to that at the bottom, C2, is used. A C,/C, ratio of 0.9 to 1.0 indicates very good Cl - = the ratio of water concentration at the top (C,) dispersion while aratio of 0.4 or smaller indicates poor dis- 2 to that at the bottom ( , C) persion with a high potential for water stratification. Calcu- lations giving ratios less than 0.7 should not be considered W = the settling rate ofthewater droplets reliable as coalescence of water droplets invalidates the pre- EID = the turbulence characteristic, where E is the diction technique. eddy diffusivity and D the pipe diameter 17COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 23. API M P M S * 8 - 2 95 m 0732290 0549033 T55 m 18 CHAPTER 8-SAMPLING Table B-1-Comparison of Mixing Devices 2 4 6 8 12 !O 3 50 Pump A P (bar) X- -x-x- (X -- X " ) - X 0.8 0.7 0.6 0.5 0.4 O.? 0.25 Orifice y=dD= -x- X - - K -X- -X- - x - -X- 3.7 0.6 0.: 0.4 0.3 o.; Enlargement y=dD= X - -X- ~ -X- __ -X- -X- 1 2 4 6 3 1: ,O Throttling valve A P (bar) X- -X- -x-x "x-x- -X- Globe valve X Swing check or angle valve 60 45 90 Circular Mitre Bend 0 (dei?) " X- -X 0.8 0.7 0.5 0.1 Contraction y= d D x- --- xx< .o 4 1 Bends (5-off) r/D xX x -- " o 4 1 Bends (4-off) r, x-X -" x .O 1 Bends (3-off) r/D xx - o 1 Bends (2-off) r/D xx - .o 1 Bends ( I -off) r/D ;-X Straight pipe Gate valve x - ----- - - Resistance coefficient ( K ) 11 - I- 1- 1- 1- )- - I 2 1 4 1 11 0 2( 400.0 1000.0 Characteristic (P) 1.o 2.5 5.0 10.0 20.0 50.0 100.0 200.0 500.0 1000.0 2000.0 5000.0 Parameter of mixing element Notes: l. The table has been compiled assuming the samepipeline diameter downstream of any device. If the downstream diameter of any two devices is not identi- cal, comparisons using this table cannot be performed. 2. It is not intended that the table be used to ascertain P or K values but only to provide a comparison of the likely mixing effects of devices. 3. For centrifugal pumps and throttling valves, the dissipation energies that are defined without the use of values (see Table B-5). the comparison has been done using an assumed ßequal to WEoand thefollowing typical values: D = 0.4 m Y= 16 cSt p = 900 kg/m V = 5.6 m/s b. An alternative measure of dispersion, G , can be defined Table B-2-Dispersion Factors where: G CK, C,/C, G = - €ID IO 0.90 1.11 W 8 0.88 1.14 Table B-2 presents the relationship of C,lC, with G. 6 0.85 1.18 4 0.78 1.28 It is important to note that the uncertainty of the calcula- tions is such that errors in G of more than 20 percent may re- 3 0.71 1.41 sult at low values of G. For this reason, it is recommended 2 0.6 1 I .64 that no reliance beplaced on calculated G values of less than 1.5 0.5 1 1.96 3 and that additional energy dissipation calculated G value. 1 0.37 2.70COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 24. A P I MPMS*8.2 75 0732290 0549032 771 m SECTION 2”STANDARD PRACTICE FOR AUTOMATIC SAMPLING OF LIOUID PETROLEUM AND PETROLEUM PRODUCTS 19 6.3 Determination of EnergyDissipation Where v is given in mm2/s (cst). Suggested values of P and tentative relationships for E 6.3.1 METHOD A (other than E = ßEo) are given in Tables B-4 and B-5 re- Using the relationship: spectively. Table B-4-Dissipation Energy Factors (P) Where: n r/d = 1 1.5 2 3 4 5 10 AP = the pressure drop across the piping element n= 1 1.27 1.25 1.23 1.22 1.18 1.15 1.07 V = the flow rate at the pipe section in which energy n=2 1.55 1.50 1.48 1.45 1.38 1.30 1.13 is dissipated n=3 1.90 1.80 1.75 1.70 1.56 1.44 1.18 AX = a characteristic length that represents the dis- n=4 2.20 2.10 2.00 1.93 1.72 1.56 1.23 tance in which energy has been dissipated n=5 2.60 2.40 2.30 2.20 1.90 1.70 1.28 In most cases AX is not known with any confidence. Wher- Notes: ever possible, the value to be used should be supported by 1. IZ is the number of bends of radius r in a pipe of diameter D. experimental data. 2. The spacing between the bends may affect the degree of dispersion. For Note 1: If AX is not known, a substitute value of AX = 1OD may be used this relationship to hold the distance between each bend should not exceed as avery rough approximation for devices of low mixing efficiency such as 30 pipe diameters. those in Table B-3. For specially designed high-efficiency static mixers the value AX will be small and should be obtained from the designer. Contraction: fi = 2.5( 1 - f) Note 2: If A P is not known, calculate it from: 5u -UZY Enlargement: A- p KpV? P 2 where K is the resistance coefficient of the piping element under consider- ation. Suggested values of K for different piping elements are given i n Table B-3. Table B-5-Dissipation Energy Relationships Centrifugal Pump Table B-3“Suggested Resistance Coefficients (K) E 0.125 - = ApQ Contraction K=0.5(1 -y’ (O 5 K 5 0.5) PD3 Throttling Valve Enlargement K=- (1 - Y)2 (O 5 K 5 0.5) u‘ E = - AP V 1 4 20pD Orifice K = 2.8 ( 1 - ?)[[-J - I] Y Flow Nozzle Circular mitre bends K = 1.2 (1 - cose) vj3 where B = turn angle (O 5 K 5 1.2) E = 0.022 - 1 Swing check valve K=2 Angle valve K=2 8.4 MeanWater Droplet Diameter Globe valve K=6 The mean water droplet diameter d may be estimated us- Gate valve K = 0.15 ing: Note: y is the small diarneter/large diameter and K is based on the velocity in the smaller pipe. d = 0.3625 - (E)”” where v is the droplet surface tension between water oil and 8.3.2 METHOD B All measured in Newtons per meter. formulas and examples in this appendix assume v = 0.025 N/m. Using the relationship: Interfacial tension values may be significantly affected by E = ßEo additives and contaminants. If it is known that the value is Where: other than 0.025 Newtons per meter, the water droplet set- tling velocity W , given in B.5, should be modified by multi- P = a characteristic parameter of a mixing element. plying by: E, = the rate of energy dissipation in a straight pipe. E, is calculated from: E, = o,o05fl25~-1.?5 2 . 7 5 ~COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 25. 20 CHAPTER 8”SAMPLING B.5 Water Droplet Settling Velocity i. Calculate the water droplet settling rate using: The determination of either of the dispersion factors re- W = - €/D G quires a knowledge of the water droplet settling rate, W. This can be calculated using the relationship: j. Determine the energy required to produce desired pro- the file concentration ratio using the formula presented in B.5 855(pd - p)E-O.’ rewritten in the form: W= v$-‘ Where: pd = the water density. For salt water (from wells or k. Select from Table B-1 those of the available piping ele- tankers) a suggestedvalue is 1025 kg/m3if the ments most likely to provide adequate energy dissipation. actual one is not available. 1. Calculate the dissipation energy E for the selected piping than 5 percent, If the mean water concentration is higher elements using either of the methods describedin B.3. multiply Wby 1.2. m. Compare Er with E to determine if an acceptableprofile can be achieved. If, for any pipingelement E E, then a sat- isfactory profile can be achievedusing that element. If E < B.6 TurbulenceCharacteristic E, for all piping elements, then additional dissipation energy Determination of either of the dispersion factors requires must be provided. This can done by reducing the pipe di- be the turbulence characteristics EID to be evaluated using: ameter (a length > 1OD is recommended) by introducing an additional piping element, or by incorporating astatic or dy- - - 6.313 X E ~ ~ - ~ ~ ~ . 8 7 5 ~ - ~ . l 2 5 ~ ~ . l 2 ~ namic mixer. D n. If the flow rate has been increased by reducing the pipe diameter, repeat Steps hto m. B.7 Verification of an Existing Sampler o. If a new piping element hasbeen introduced into the sys- Location tem without.changing the flow rate, check, using (l), that step its dissipation energy is larger than the best so far achieved It is important to select the worst-case conditions in the and, if so, proceed to Step m. following sequenceof steps: p. If a static or dynamic mixer is considered, thenthe man- a. Determine the desired profile concentration ration Cl/C2 ufacturer should be consulted as to its design and applica- and, using TableB-2, the corresponding value of G. tion. b. Determine, using Table B-1, which pipeline fittings within 3 0 0 upstream of the sampler are most likely to pro- vide adequate dispersion. B.9 Examples c. Estimate the energy available from each the most likely of fittings using either of the methods describedin B.3. 6.9.1 VERIFICATION OF ANEXISTING d. Calculate the value of G from the highest value of avail- SAMPLER LOCATION able energy obtainedin step (c) using the formulas presented in B.2, B.5, and B.6. Use the procedure in B.7. e. Obtain the C,lC, ratio from Table B-2. For an installation in a 500-millimeter pipe where the f. Check that the calculated C , / C , (or G) value is higher most severe operating conditions represented by: are than the desired value obtained in Step a. If it is, the sampler v = 2m/s location .hould prove suitable for the application. If not, re- p = 850 kg/m3 medial action should be taken. v = 8 cSt Pd = 1025 kg/m3 8.8 Selection of a Suitable Sampler a. The desired W C 2 ratio is 0.9. Location From Table B-2, G = 10. b. The pipeline fittings within 3 0 0 upstream of the sampler It is again very important to select the worst and con- case are a globevalve, an enlargement with diameter ratio y = 0.5 tinue the above sequence. and two 90-degree bends. g. Determine the desired profile concentration ratio C,/C, From Table B- 1 , the globe valve or the enlargement is and, using Table B-2, the corresponding value of G. clearly most likely to provide adequatedispersion. h. Determine the turbulence characteristic C/D asdescribed c. The energy available may be calculated using either in B.6. method A or B of B.3. However, onlyK values are given forCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 26. A P I MPMS*8.2 95 m 0732290 0549034 764 m SECTION 2"STANDARD PRACTICE FOR AUTOMATIC SAMPLING OF LIQUID PETROLEUM AND PETROLEUM PRoDUCTS 21 the globe valve; therefore, these must used to compare the be likely mixing effects of the globe valve and the enlargement. 1 Globe valve K =6 (Table B-3) :. E = 45 X 0.005 X X - 22.75 X 0.51.25 Enlargement K = (1 - 7 3 =9 (Table B-3) = 6.0545 Wkg 9 The enlargement has the higher K value and should be used d. in the following calculations. EID G= - (Table B-2) Note: As the enlargement is to be used to estimate theenergy available, ei- W ther method A or B of B.3 may be used for the rest of the calculation. EID = 16.37 X m/s If using method A, continue as follows: E = - APV as calculated for methodA. AXp or as K V2 AP = Wkg 2 - 855(1025 - 850) x 1 - " then 8 X 8502.2 6.0545°.8 E = - Kv3 2Ax andusing AX = IOD 16.37 X 10-3 = : G . = E= x 23 = 7.2 Wkg 1.59 X 10-3 2 X 10 X 0.5 Steps e and f follow as for method A. 8.9.2 SELECTION OF A SUITABLE SAMPLER LOCATION Use the procedure in B.8. The proposed pipeline configuration consists a 600- of millimeter line enlargingto 800-millimeter followed by a line of three 90-degree bends each with an r to D ratio of 1, and finally a throttling valve with thedifferential pressure of 1 bar. = 16.37 X 10-3m/~ The most severe operating conditions are represented by: V = 1.5 m / s and p = 820 kg/m3 855(1025 - 850) 1 v = 7 cst W= X- 8 X 8502.2 7.2°.8 pd = 1025 kg/m3 g. The desired CJC, ratio is 0.9. FromTable B-2, G = 10. h. The turbulence characteristic from B.6 is: 16.37 X lo=? = : . G= 1-38 X 10-3 e. From Table B-2 the C,IC2ratio is greater than 0.9. f. The calculated value of C,K, is greater than the required value and therefore adequate conditions for sampling exist. If using method B, continue as follows: E = ßEoWkg i. The water droplet settling velocity is: 5(1 - = 45 P= .p (Table B-4)COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 27. A P I MPMS*8-2 95 m 0 7 3 2 2 9 0 0 5 4 9 0 3 5 bTO m 22 CHAPTER 8"SAMPLING j. The energy dissipation rate required is: h. = 20.25 X m/s 1. = 13.99 Wkg k. From Table B-1 the throttling valve is clearly the element most likely to provide sufficient energy dissipation. 1. Method B is the only one to provide an energy dissipa- tion formula for a throttling valve; see Table B-5. = 7.13 Wkg APV ..E = -Wkg 20pD k. Unchanged from previouscalculation. 1. - - x los x [ l bar = lo5 Pascal] 20 X 820 X 0.8 = 11.43 Wkg - 105 x 2.67 20 X 820 X 0.6 m. The energy dissipation rate E provided by the throttling valve is less than required E,.. Therefore a G value of 10 has = 27.10 Wkg not been achieved and sampling from this location is un- likely to prove adequate. If the enlargement from 600 800 to m. The energy dissipation rate provided by the throttling millimeters is moved downstream of the throttling valve and valve located in the smaller diameter pipeis more than suf- sampling location, then the following recalculation applies ficient to give a G value of 10. Adequate sampling should with D = 0.6 m and V = 2.67 &s. therefore be possible.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 28. A P I M P M S * d - Z 75 0732290 0549036 537 m APPENDIX C-COMPARISON OF PERCENT SEDIMENT AND WATER VERSUS UNLOADING TIME PERIOD 13- 12- 11 - 10 - 9- 8- m Crude-33.1 "API. 7- Indicated 1600 barrels of free water in 450,000 barrels cargo. 6- m All working compartments open to unloading pumps suction. 5- m Pumping rate 8,000 barreldhour initially, up to 35,000 barreWhoUrin 30 minutes. 4- 3- 2- 1- Start 30 60 150 90 120 unloading Unloading time period (minutes) 23COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 29. A P I MPMS*A-2 95 0732290 0549037 473 m APPENDIX D-FREQUENTLY USED FORMULAS AND EQUIVALENTS Velocity: V = Q/A 0.4085 gpm - 0.2859 bph - 0.0028368 gpm v= dz - d2 - D2 - - 0.00 1985 bph D2 Where: V = flow velocity, feet per second Q = flow rate, cubic feet per second A = area of pipe, square feet d = internal diameter of circular pipe, inches D = internal diameter of circular pipe, feet gpm = U.S. gallons per minute bph = barrels (42 gallons) per hour Velocity equivalents: d s e c = 0.3048 ft/sec ft/sec = 3.2808 &sec 25COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 30. A P I MPMS*8.2 95 E 0732290 0549038 30T E APPENDIX E-DESIGN DATA SHEET FOR AUTOMATIC SAMPLING SYSTEMS II) B a: O cl 4 v) Y W I 5 I l - a 4 a O > 27COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 31. A P I MPMS*b*Z 75 m 0732270 0547037 246 m APPENDIX F-PERFORMANCE CRITERIA FOR PERMANENT INSTALLATIONS F.1 Calculations Prior Operation to b. Controller-to-probe link. c. Probe operation. PVC = expected parcel volume, m3 2. Performance factor (PP) b = expected extractor grab size, ml SV PF = -= 1 2 0.10 SVe = expectedsample volume, ml SVc = (normally 80% of receiver capacity) SV n = number of sample grabs expected - - r= 1 2 0.10 -Xb B n = - SVe b 3. Flow sensor accuracy (SA) B = frequency of sampling, m3/grab PV (controller input) S = m = 1 5 0.10 A pv, B = -PVe 4. Sampling time factor (SF) n Total sampling time - SF = - 1 2 0.05 Total parcel time F.2 Data From the Sampling Operation Time parcel began Time parcel completed N = total number of grabs recorded by the Total parcel time controller Time sampler begins operation SV = sample volume collected, ml Intermittent outages SVc = sample volume calculated, ml Time sampler stops operation Total sampling time PVs = parcel volume measured by sampler flow is Note: Record actual times sampler not in service. sensing device,m3 5. Sampler installation was tested according to MPMS PVC, = custody transfer or outturn parcel volume, m3 Chapter 8.2 Yes No Date tested F.3 Calculation of Performance Report Components and variables involved: a. Average grab size. The following calculations can be helpful in evaluating if Flow b. sensor-to-controller link. a sample is representative: c. Controller. l. Grab factor ( G F ) d. Controller-to-probe link. e. Probe operation. GF=-- - 1 2 0.05 f. Flow sensor accuracy. NXb Note: Temperature compensation of volume may be required if oil is sam- Components and variables involved: than that of the accumulated volume in the pled at a temperature different size. Average grab a. receiver. 29COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 32. APPENDIX G-PERFORMANCE CRITERIA FOR PORTABLE SAMPLING UNITS Representative sampling ismoredifficult to document 1. Grab factor (CF) portable verify sampler when a and is used. Thesensing flow SV device limited usually is in accuracy and turndown. Stream GF = - 1 ? 0.05 N X b = conditioning is usually limited to piping elements and flow velocity. The sampler controller data logging is usually lim- 2. Modified performance factor (PF,,) ited. precautions Special and operating procedures with ad- SV PF, = = 1 2 0.10 ditional record keeping by the operator can overcome these -pX s vb limitations. B PV- is normally not available. When this is the case, use P t o , which excludes the effect of flow sensor malfunction G.l CalculationsPrior to Operation or inaccuracy on PF,. If PV, is available from the controller, PV, = expected parcel volume, m3 calculate PF as in Appendix F. b = expected extractor grab size, ml 3. Flow sensor accuracy (SA) The volume as measured bythe sampler(s) flow sensor(s) is SVe = expected sample volume,ml normally not available. The volume measured by the flow (normally 80% of receiver capacity) sensor(s) is calculated from the number of grabs ordered by n = number of sample grabs expected the controller(s). B = Frequency of sampling, m3/grab 4. Sampling factor (SF) (controller input) Total sampling time = o.o5 SF = Total Darce1 time B=!.% n 5. Stream conditioning: a. For 95 percent of the volume sample, the flow rate in piping ahead of each sampler was a minimum of 2.1 me- G.2 from Data the Sampling Operation terdsecond (7.0 feeusecond) Yes No N = total numberof grabs recordedbythecon- troller b. No more thanthe percent total 10 of free water the in tanks/compartments was pumped at flow rates of less SV = sample volume collected, ml than 2.1 metersheconds. PV, = parcelvolumemeasuredby sampler flow Yes No sensing device, m 3 The criteria for stream conditioning is met both answers if PVC, = custodytransfer or outturnparcelvolume,m3 are “Yes”. 6. Line and manifold data Complete forms as shown in Tables G-1 and G-2 and Fig- G.3 Calculation of PerformanceReport ures G-1 and G-2 for each sample. Note: Temperature compensation of volume may be required if oil is sam- The can be in if pled at a temperature different than that of the accumulated volume in the representative: is a sample receiver.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 33. A P I MPMS*8-2 95 0732290 0549043 9 T 4 m 32 CHAPTER 8”SAMPLING Table G-1-Portable Sampler Operational Data Confirmation of Mixing and Flow Sensor Velocity Vessel Location Loading Discharge Pumping Time Begins- Ends Date Pumping Begins I I l I I I Line No. = Identification letteror number from Figure G-1 or G-2. Velocities shouldbe calculated forlines A-D in Figure G-1 as major ratechanges occur and armshoses are added or removed fromservice. The same applies to spools 1 4 on the vessel. The same applies for lines and spools designated 1 - 4 in Figure G-2.COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 34. A P I M P M S * 8 * 2 95 D 0732290 0549042 830 m SECTION 2 s T A N D A R D PRACTICE FOR AUTOMATIC SAMPLING OF LIQUID PETROLEUM AND PETROLEUM PRODUCTS 33 Table G-2-Portable Sampler Operational Data Confirmation of Free Water Sampled VESSEL -LOCATION -DATE- TANK OR INITIAL PUMPING CALCULATIONS FOR PIPE VELOCITY AT SAMPLER COMPARTMENT FREE WATER BEGINS VELOCITY AT WHEN PUMPING BEGINS I Notes: 1, Free water is assumed to be pumped from a tank or compartment with the initial 5 percent of the volume pumped. 2. A sample cannot be judged representative if more than 10 percent of the water found in the total parcel after the operation is complete is pumped as free water and the velocity in the piping ahead of the sampler at the time of pumping is less than 2.44 meters/second (8 feevsecond).COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 35. A P I M P M S * 8 * 2 95 m 0732290 0549043 777 m 34 CHAPTER 8”SAMPLING Tanks l I Lines to Dock Lines and Arms andor Hoses on the Dock I I Sampler Spools on Vessel €3 ii I I i Tank no. - I Ii I + ” Line no. i i I A Ii Line size - €J i i - I I Line size __ Line no. B Line no. 2 Vessel c +=I+ i i - Tank no. - manifold ArdHose size - Line size - ____t I Line size - I i i I Line size - i I Line no. 3 €I i Tank no. - I I ArdHose size __ A i I Line size - i I i I I” Line no. 4 Line size - i I ArdHose size - I I I rl i Tank no. - l I Sampler spool diameter - Figure G-1-Typical Piping Schematic to Be Recorded for LoadingCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 36. SECTION 2”STANDARO PRACTICE FOR AUTOMATIC SAMPLING OF LIQUID PETROLEUM AND PETROLEUM PRODUCTS 35 Lines from Vessel Vessel Manifold and Sampler Spools Pump Room to Manifold I Line no. 1 I Line size- I I Line no. 2 c Line size__ I Vessel manifold +“lab Line size~ I Line size___ I Line size- I Line no. 3 Line size~ I I Line no. 4 I I -(t- “a”+ Line size__ Sample spool diameter Figure G-2-Typical Piping Schematic to Be Recorded for DischargesCOPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 37. API M P M S * 8 * 2 95 0732290 0549045 54T m APPENDIX H-PRECAUTIONARY INFORMATION H.l PhysicalCharacteristicsandFire ical, concentration, and length of the exposure. Everyone Considerations should minimize hisor her exposureto workplace chemicals. The following general precautions are suggested: H.l.l Personnel involved in the handling of petroleum- related substances (and other chemical materials) should be a. Minimize skin and eye contact and breathing of vapors. familiar with their physical chemical characteristics, in- and b. Keep chemicals away from the mouth; theycan be harm- cluding potential for fire, explosion, and reactivity, and ap- ful orfatal if swallowed or aspirated. propriate emergency procedures. These procedures should comply with the individual company’s safe operating prac- c. Keep containers closed when not in use. tices and local,state, and federal regulations, including those d. Keep work areas asclean as possible and well ventilated. covering the use of proper protective clothing and equip- e. Clean up spills promptly and in accordance with pertinent ment. Personnel shouldbe alert to avoid potential sourcesof safety, health, and environmental regulations. ignition and should keep the materials’ containers closed f. Observe established exposure limits and use proper pro- when not in use. tective clothing and equipment. H.1.2 AP1 Publication 2217 and Publication 2026 and any Information on exposure limits can be found by consult- applicable regulations should be consulted when sampling ing the most recent editions of the Occupational Safetyand requires entry into confined spaces. Health Standards,29 Code of Federal Regulations Sections 11910.1000 and following, and the ACGIH publication H.1.3 INFORMATION REGARDING PARTICULAR Threshold Limit Valuesfor Chemical Substances and Phys- MATERIALSANDCONDITIONS SHOULD BE OB- ical Agents in the Work Environment. TAINED FROM THE EMPLOYER, THE MANUFAC- TURER OR SUPPLIER OF THAT MATERIAL, OR THE H.2.2 INFORMATION CONCERNING SAFETY AND MATERIAL SAFETY DATA SHEET. HEALTH RISKS AND PROPER PRECAUTIONS WITH RESPECT TO PARTICULAR MATERIALS AND CON- H.2 SafetyandHealthConsiderations DITIONS SHOULD BE OBTAINED FROM THE EM- H.2.1 Potential health effects can result from exposure to PLOYER, THE MANUFACTURER, ORTHE MATERIAL any chemical and are dependent the toxicity of the chem- on SAFETY DATA SHEET. 37COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 38. APPENDIX I-SAMPLER ACCEPTANCE TEST DATA SHEETATION: COMPANY: TEST # -OF DATE: WITNESS: WITNESS: OTHER SYSTEM DATA CRUDE GRADE VISCOSIPI: API: FLOW RATE VELOCITY: LINE SIZP lms CtSB4OC bWm, fpslmps FLOW TEMP: FIC CRUDE VOLUME DETERMINATIONBY: PROBE DESIGN: PROBE ORIENTATION: STREAM CONDITIONING: LABORATORY ANALYSIS: TANK METER ISOKINETIC TOP POWER MIXING CENTRIFUGE TANK INCREMENTVOL. ELL SIDE STATIC MIXER-VERTICAL DISTILLATION bbldm, BEVELED _ _ BOTTOM STATIC MIXER-HORIZONTAL ~ KARL FISCHER ~ PLAIN PIPING ELEMENT-VERTICAL SAMPLE MASS LOOP PIPING ELEMENT-HORIZONTAL OTHER SAMPLE RECEIVER VOLUME: VOLUME GAUL GRAB S E (ML) NONE TEST WATER: TEST SAMPLE VOLUME: FRESH GAUL BRACKISH SEA PRODUCTION TEST DATA BASELINETEST DATA SINGLE SAMPLER METHOD BASELINE TEST: l. - - (1ST BASELINE % + ZNDBASELINE %) I2 = % (%g) 2. DUAL SAMPLER METHOD BASELINETEST A. BEFORE WATER INJECTION COMPARISON TEST (BASELINE SAMPLER - % SAMPLER PRIMARY X) = - % MAXIMUM DEVIATION FROM TABLE A-1 - - - % B. DURING WATER INJECTION TEST (Wav,) - - % WATER INJECTION AND CRUDE VOLUMES: 3.WATER INJECTED (V)TOTALIZERMETER STOP START METER TOTALIZER gallliter V = DIFFERENCE gaUliter x X - bbldm3 (METER FACTOR) gaUbbl OR 0.001 Urn3) (0.0238 ~ ~~ 4. CRUDE VOLUME TANK STOP OR METER bbl/rn3 TOTALIZER STARTTANK OR METER TOTALIZER DIFFERENCE bbllm3 x - - bbls/m3 (METER FACTOR, AS APPLICABLE) 5.TOV (LINE 3 + LINE 4) - - bbldm CALCULATIONS: D , = (Wbst + Wbl) - Win, WHERE: WIOst = PERCENT WATER IN TEST SAMPLE 6. W, =, W , X [(TOV - V) I TOV] - - x [ ( - ) I I (LINE 1 OR 2 B) (LINE 5) (LINE 3) (LINE 5) 7. W,"¡ = (VrrOV) x 100 =( / ) X 1O0 % (LINE 3) (LINE 5) MAXIMUM DEVIATIONTABLE FROM A-1 - -% Comments: Notes: I. All percent figures are percent volume. is 2. Correct the volume of water injected for solids content, as applicable, if production water used. 3. Deviations must be within limits outlined in MPMS Chapter 8.2, Table A-l. 4. Note below any physical or procedural changes made between consecutive test runs. 5. Attach copy of sampler receiver-mixer proving test report. MPMS Chapter 8.3. See 39 COPYRIGHT American Petroleum Institute Licensed by Information Handling Services
  • 39. 1-01102-10/95-7.5C(TE)COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services
  • 40. A P I M P M S * 8 @ 2 95 m 0732270 0547098 259 m ADDITIONAL COPIES AVAILABLEFROM PUBLICATIONS DISTRIBUTION AND (202) 682-8375 American 1220 L Street, Northwest Petroleum Washington, D.C. 20005-4070 Institute 202-682-8000 Order No. H08022COPYRIGHT American Petroleum InstituteLicensed by Information Handling Services