SABP-A-015

Best Practice SABP-A-015

1 July 2007

Chemical Injection Systems Document Responsibility: Materials and Corrosion Control Standards Committee

Saudi Aramco DeskTop Standards Table of Contents 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18

Introduction............................................................................ 2 References............................................................................ 3 Definitions and Abbreviations................................................ 6 Chemical Injection Overview................................................. 7 Chemical Injection System Design...................................... 11 Chemical Injection Point Position........................................ 23 Chemical Injection System Inspection................................ 25 Management of Change...................................................... 25 Chemical Injection System Maintenance............................ 26 Injection Point Documentation............................................ 27 Safety.................................................................................. 28 Refinery Chemicals and Water Wash Injection................... 29 Upstream Facilities and Gas Plants Chemical Injection...... 47 Steam Generator Chemical Injection.................................. 51 Chemical Dosage Control................................................... 52 Chemical Injection Effectiveness........................................ 53 Strategies for Chemical Optimization.................................. 55 Quality Control of Chemicals............................................... 57

Appendix A.................................................................................. 58

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Next Planned Update: TBD Page 1 of 58

Primary contacts: Ahmed M. Al-Zahrani on 874-6132 or Ahmad S. Al-Omari on 874-7431 Copyright©Saudi Aramco 2007. All rights reserved.

Document Responsibility: Materials and Corrosion Control Issue Date: 1 July 2007 Next Planned Update: TBD

1

SABP-A-015 Chemical Injection Systems

Introduction 1.1

Purpose The intent of this best practice is to provide guidelines for the detailed design, materials selection, quality assurance, operations and inspection of chemical injection systems. The content is based on established industry guidelines and field experience with their use in Saudi Aramco facilities. Corrosion Technology Unit of Consulting Services Department has developed this Best Practice to assist with improving and maintaining the mechanical integrity of Saudi Aramco upstream and downstream facilities through the use of the chemical injection systems.

1.2

Scope This Best Practice covers chemical injection systems in all refining units, including wash water and chloride injection in reformer units. All upstream oil & gas processing facilities, transmission and producing pipelines and stem generators chemical injection systems have been also covered. The chemical injection system for sea water application is not covered in this document.

1.3

Conflicts with Mandatory Standards In the event of a conflict between this Best Practice and other Mandatory Saudi Aramco Engineering Requirement, please contact the supervisor of CSD/ME&CCD/Corrosion Technology Unit for resolution.

1.4

Disclaimer The material in this Best Practice document provides the most correct and accurate design guidelines available to Saudi Aramco which complies with international industry practices. This material is being provided for the general guidance and benefit of the Saudi Aramco engineers and designers. Use of this Best Practice in designing projects for Saudi Aramco, however, does not relieve the designer from his responsibility to verify the accuracy of any information presented or from his contractual liability to provide safe and sound designs that conform to Mandatory Saudi Aramco Engineering Requirements. Use of the information or material contained herein is no guarantee that the resulting product will satisfy the applicable requirements of any project. Saudi Aramco assumes no responsibility or liability whatsoever for any reliance on the information presented herein or for designs prepared by Designers in accordance with this Best Practice. Use of this Best Practice by Designers is Page 2 of 58



intended solely for, and shall be strictly limited to, Saudi Aramco projects. Saudi Aramco® is a registered trademark of the Saudi Arabian Oil Company. Copyright, Saudi Aramco, 2007. 2

References Unless stated otherwise, all Standards, Specifications and Codes referenced in this Best Practice shall be the latest issued (including revisions, addenda and supplements) and are considered a part of this Best Practice. 2.1

Saudi Aramco References Saudi Aramco Engineering Procedure SAEP-20

Equipment Inspection Schedule

Saudi Aramco Engineering Standards SAES-A-205

Oilfield Chemicals

SAES-A-208

Water Treatment Chemicals

SAES-A-206

Positive Material Identification

SAES-A-301

Materials Resistant to Sulfide Stress Corrosion Cracking

SAES-B-005

Spacing and Diking for Atmospheric and Low Pressure Tanks

SAES-D-109

Design of Small Tanks

SAES-G-006

Positive Displacement Pumps - Controlled Volume

SAES-J-400

Temperature

SAES-L-105

Piping Material Specifications

SAES-L-110

Limitations on Pipe Joints and Components

SAES-L-132

Material Selection for Piping Systems

SAES-Q-005

Concrete Foundations

Saudi Aramco Materials System Specifications 31-SAMSS-009

Positive Displacement Pumps - Controlled Volume

32-SAMSS-030

Manufacture of Small Tanks

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Saudi Aramco Library Drawings DA-950035-001

2-inch high Pressure Access System Chemical Injection and Corrosion Monitoring

DB-950175-001

Antifoulant Injection Point Details

DB-950176-001

Water Wash Injection Point Details

DB-950177-001

Caustic Injection Point Details

DB-950178-001

Neutralizing Amine Injection Point Details

DB-950179-001

Filming Amine Injection Point Details

Saudi Aramco Best Practice SABP-A-016

Crude Unit Corrosion Control

Saudi Aramco Engineering Reports SAER-2365

Saudi Aramco Mothball Manual

SAER-5941

Final Report and Guidelines on Crude Unit Overhead Corrosion Control

Saudi Aramco Inspection Procedures

2.2

00-SAIP-07

Positive Material Identification Requirements

01-SAIP-04

Injection Point Inspection Program

Industry Codes and Standards American Petroleum Institute API RP 570

Piping Inspection Code Inspection, Repair, Alteration, and Rerating of In-Service Piping Systems

American Society of Mechanical Engineers ASME B31.3

Process Piping

ASME B16.9

Factory-Made Wrought Buttwelding Fittings

Manufacturers Standardization Society of the Valve and Fittings Industry, Inc. MSS SP-97

Integrally Reinforced Forged Branch Outlet Fittings - Socket Welding, Threaded, and Buttwelding Ends

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2.3


Other References J. G. Willmon and M. A. Edwards, “Precommissioning to Startup: Getting Chemical Injection Right”, SPE 96144, SPE Annual Technical Conference and Exhibition, Dallas, Texas, 9 – 12 October 2005. J. W. Palmer, W. Hedges and J.L. Dawson, “Use of Corrosion Inhibitors in Oil and Gas Production: (EFC 39)”, Woodhead Publishing, 2004. W. C. Fortt, E. S. Berm, R. C. Strong and Ma. Vegesi" Process Design of Injection Systems" Corrosion 96, NACE International, Paper No. 587, 1996. R. R. Konet; G.J. Honer and R.M. Thompson, “Implementation Strategies for API RP 570 Injection Point Inspection Programs”, Corrosion 96, NACE International, Paper No. 588, 1996. R. C. Quinter, "Performance Verification of Injection Systems", Corrosion 96, NACE International, paper No. 590, 1996. J. Gutzeit, "Problems with Injection Facilities for Process Additives or Wash Water", Corrosion 96, NACE International, paper No. 591, 1996. P. R. Petersen, “The Use of Corrosion Inhibitors in the Refining Industry”, Corrosion 96, NACE International, paper No. 594, 1996. A. Bagdasarian, J. Feather, B. Hull, R. Stephenson and R. Strong, “Crude Unit Corrosion and Corrosion Control”, Corrosion 96, NACE International, Paper No. 615, 1996. J. R. Rue and J. G. Edmondson, “Control of Salt-Initiated Corrosion in Crude Unit Overhead Systems”, Corrosion 2001, NACE International, Paper No. 01538, 2001. D. E. Powell, D. I. Ma’ruf, and I. Y. Rahman, “Field-Testing Corrosion Inhibitors in Oil and Gas Gathering Systems”, Materials Performance, p. 42-45, August 2002. D. W. Alley and N. D. Coble, “Corrosion Inhibitors for Crude Distillation Columns”, Materials Performance, p. 44-49, May 2003. NACE International Publication # 3410: Refinery Injection and Process Mixing Points (prepared by Task Group 174) Nalco Best Practices Chevron Best Practices

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3


Definitions and Abbreviations Be°: Baumé is a scale used to measure the density of various liquids. Catalyst: A material that aids or promotes a chemical reaction between other substances but does not react itself. Catalyst increases reaction speed and can provide control by increasing desirable reactions and decreasing undesirable reactions. CCR: Continuous Catalyst Regeneration CHB: Chemical Hazard Bulletin. CHB is an internal company document (available in both English & Arabic) developed by Environmental Protection Department to provide a standardized one-page summary of a material’s hazard ratings: health hazards, fire & reactivity, handling, storage & disposal and first aid information for use in the handling of hazardous materials. It is known also as Material Safety Datasheet, MSDS. CRA: Corrosion Resistant Alloy ER: Electrical Resistance Fouling: Accumulation of deposits in condensers, exchangers, etc. GOSP: Gas Oil Separation Plant HPPT: High Pressure Production Trap IPPT: Intermediate Pressure Production Trap LPPT: Low Pressure Production Trap LPR: Linear Polarization Resistance LPI: Liquid Penetrant Inspection MSDS: Material Safety Datasheet. MSDS is a document containing information on hazardous ingredients, their properties, and precautions for use for a specific chemical substance. MPI: Magnetic Particle Inspection NGL: Natural Gas Liquids OSI: On-Stream Inspection PMI: Positive Material Identification PWHT: Post-Weld Heat Treatment Page 6 of 58



QA/QC: Quality Assurance/Quality Control RSS Report: Refinery Shift Superintendent Report RT: Radiography Test Stress Corrosion Cracking: (SCC) is the cracking induced from the combined influence of tensile stress and a corrosive environment. SARCOP: Saudi Aramco Refining Chemical Optimization Program T&I: Test & Inspection TDS: Total Dissolved Solids RVL: Restricted Vendor List, generated by Saudi Aramco “Typical” or “Target”: indicate desirable but not mandatory items “Limit,” “Required,” “Shall,” and “Must”: indicate mandatory items 4

Chemical Injection Overview Chemicals play an important role in the enhancement of oil and gas production and processing. They control corrosion, prevent organic and inorganic deposits, aid in phase separation, control microbial problems, control pH, scavenge oxygen and neutralize chlorides. Chemical injection philosophy depends primarily on the fluid composition, fluid chemistry, operating pressures and temperatures, and to some extent the flow regime. Depending on fluid characteristics and system materials, a wide range of chemicals maybe injected into vessels and piping system to control corrosion. Chemical injection is considered one of several corrosion mitigation methods such as coating, material selection, cathodic protection, process control, use of CRAs, etc. Chemical injection systems are an invaluable component of corrosion control systems implemented in a variety of operating units. For example, one of the chemical injections is corrosion inhibitor that is used to form a stable adherent film on the internal surface of a pipe or vessel, which acts as a barrier between the equipment surface and the corrosive media. Also, the injection system could be used to neutralize or dilute the components of the process stream. Inhibitors can be added either as a batch or as a continuous injection. Chemicals can be applied through a variety of mechanisms. There are three typical configurations of injection systems used in hydrocarbon production and processing: retrievable (high pressure), retractable (low pressure) and fixed (high or low pressure). Page 7 of 58



The retrievable system allows operators to undertake injection, retrieve, inspect and maintain equipment while the system is under full operating conditions. The oil and gas production industry from the wellhead through the GOSP generally employs retrievable injection systems (Figure 1) that operate with high pressure access fittings. The unit assembly consists of an access fitting, a solid plug, an injection nut, and an injection tube (quill, cross head or perpendicular spray nozzle).

Figure 1 - Retrievable Type Injection System The retractable type injection system (Figure 2) is commonly used in the refining operations. A retractable quill style injector, which has a packing gland design, offers the ability to remove and service the injector system during normal operations. This design can be manually retracted from lines or other equipment operating at low pressure.

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Figure 2 - Retractable Type Injection System The fixed assembly (Figure 3) is recommended for use in a by-pass loop which can be isolated, or in systems having frequent and regular shut-down, since system depressurization is required during insertion and removal. The unit is ideally suited for use in high pressure and/or hazardous applications where threaded fittings are not recommended to avoid leakage. Process shutdown or process isolation is required for installation and inspection. The unit assembly consists of a flange and an insertion rod with an injection quill.

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Figure 3 - Fixed Type Injection System Table-1 summarizes the configurations of chemical injection and their applications. Table 1 - Injection System Styles Configuration

Pressure Range

Facility

Retractable

Low

Refineries

Retrievable

High

Upstream Facilities

Fixed*

All

All

* While fixed systems could be employed in a wide variety of situations, their limited flexibility with regard to serviceability and maintenance typically restricts their application to more extreme or hazardous services.

The following factors can have significant impact on the safety, maintenance, operation, and service life of the chemical injection system: ●

Chemical solution being injected

●

Concentration (both of the chemical being injected and the mixed chemical/process stream, i.e., concentrated sulfuric acid injection into an RO water stream)

●

Flow rates (both stream receiving the injection and the product injected)

●

Viscosity

●

Chemical hazard

●

Materials of construction

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5


Chemical Injection System Design A typical chemical injection system (Figure 4) should consist of a chemical supply storage tank from which the chemical solution shall be pumped through piping or tubing, as appropriate, to the point of application. Each chemical feed system shall include controlled volume pumps, tanks, gauges, strainer, filter, pressure relief valves, sight glasses and flow metering/monitoring devices, check valves, hand valves, a power source for the pump and instrumentation to control the injection and to monitor its effectiveness. The chemical injection system must be well designed to accommodate the chemical types and volumes that are considered necessary for efficient operation throughout the project lifetime. All systems should be appropriately sized to handle the ‘worse-case’ scenarios. Figure 4 illustrates a diagrammatic view of the main components of the chemical injection skid.

Figure 4 - Chemical Injection System Simplified Drawing 5.1

Materials Materials of construction for the chemical injection system components should be carefully selected and shall be compatible with chemical solution and be capable of withstanding maximum pump discharge line pressure and process main pressure. Concentrated chemicals by themselves can be corrosive until properly diluted by the produced fluids. Chemicals identified as oilfield treatment chemicals, such as biocides, corrosion inhibitors, scale inhibitors, demulsifiers, and boiler treatment chemicals shall use Page 11 of 58



316L material as designated in SAES-L-132 for piping, tanks, and injection quills. Other products which do not meet these guidelines, such as strong acids, or inhibitors injected in refinery process systems, etc., shall be assessed on a case by case basis in coordination with ME&CCD. Moreover, specific materials for some applications have been addressed on their relevant sections on this Best Practice. Non-metallic materials may be an acceptable alternative for certain purposes if and only if allowed in specific sections of this document. When handling chemical solutions where the solvent is water or when injecting water streams, dissimilar metal flanged joints shall use insulation kits. 5.2

Chemical Storage Tank The chemical storage tanks should be sufficiently sized so that re-filling is not required every day. The size of chemical storage tank depends on their exact application. Chemical storage tanks in offshore upstream operations are normally sized for 3 months use. Chemical storage tanks in refineries are usually sized to provide at least one month’s capacity. Some applications, such as caustic (NaOH) in a refinery, may use local unit tanks that are made up on a batch basis from a bulk supply. Such local unit tanks should have a minimum of one day’s capacity. The chemical tank shall be equipped with a fill nozzle, vent, discharge, level instrument and drain. The chemical storage tank level should be monitored. Tanks shall be reinforced to withstand all forces when full of liquid. Chemical storage tanks should be flushed and cleaned when replacing chemical type. Chemical tanks must be properly labeled as to the contents of the tank and its hazards. Tanker connection should be accessible by road and must be clearly identified with connected tank number and product. Unloading connections shall be sealed, in order to prevent cross-contaminating chemical products, with blind flanges or if fitted with quick connect systems, i.e., Kamlock, with plugs or caps. Chemical tanks must be electrically grounded similar to any other tanks in the plant. Also, the chemical tanker must be connected to the ground system before starting chemical filling to the tank. CHB (it is also known as MSDS) shall be located near the unloading connections, in enclosures protected from direct sun, wind and rain. In general, CHBs must be readily available to the workers who are exposed to the chemical product. Containment concrete slab and curb must be constructed around the tank to contain its contents in the event of a spill or tank rupture. This concrete slab and curb must be sloped toward a drainage system. It should be noted that, any new chemicals should be included in the plants spill prevention controls. Spacing and Page 12 of 58



diking of tanks shall be in accordance with SAES-B-005. Concrete foundations for tanks shall be in accordance with SAES-Q-005. Design of chemical storage tanks up to 1500 barrels capacity shall be in accordance with SAES-D-109. This standard shall be used only by the design engineer/contractor and shall not be attached to nor made a part of a purchase order. Manufacture of these tanks shall be in accordance with 32-SAMSS-030. This specification may be attached to and form an integral part of a purchase order. Chemical tanks manufacturer shall be selected from Saudi Aramco approved RVL list. PORTA-FEED® containers, or similar tanks provided by other vendors, can be used for some applications including temporary chemical applications or limited space for construction a storage tank. Standard units are made of 304L or 316L stainless steel. For products that are corrosive to stainless steel, there are plastic and polyethylene units. The PORTA-FEED® system contains a shuttle tank and a base tank (Figure 5). The shuttle tank is used for the transportation of the product. The two tanks are connected via the filling hose. Transfer of the product from the shuttle tank is done automatically under the influence of gravity. The supplier fills a shuttle tank with a product and delivers the filled tank to the facility. When the shuttle tank empties it is disconnected and returned to the product supplier for reuse. The supplier replaces the empty tank rather than refilling it on-site.

Figure 5 - PORTA-FEED® Base Tank (Source: Nalco Company)

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The preferred mode for a PORTA-FEED® location is to stack one on top of another and drain the new one “shuttle tank” into the permanent site tank “base tank”. Some chemical tanks require nitrogen purge to exclude oxygen from the feed. Some tanks require mixers, caustic tanks in particular. These mixers should be nitrogen or mechanical. No air blowing is allowed for mixing purpose. Special materials are required for special chemicals such as caustic and sulfuric acid. The materials of construction should be per SAES-L-132. Non-metallic tanks have been used for more than 25 years successfully in the offshore Berri field. For new applications, seek the approval of CSD/ME&CCD/MEU/ Non-Metallic Group. 5.3

Pump Positive displacement pumps are frequently used for injection of chemicals into a pressurized system. The positive displacement pump must be a metering type with stroke adjustment to vary the chemical injection rate. It is important to select a pump from Saudi Aramco approved manufacturers that meet the required flow rate and pressure. The chemical injection pump needs only to be slightly higher than the internal process stream pressure. So, the positive displacement pump must be capable of generating sufficient injection line pressure to overcome injection line losses, the process line operating pressure and thus create the required pressure differential across the injection tube. To ensure online chemical injection reliability and availability, back-up, or secondary pump must be available in the event of pump failure or the need for maintenance. For critical application, the chemical injection pumps shall be provided with appropriate alarms and automated controls to provide immediate switchover from running to standby pump, in case of pump failure. All pumps must meet area classification. SAES-G-006 and 31-SAMSS-009 defines the minimum mandatory requirements governing the design and installation of positive displacement pumps-controlled volume (chemical injection pumps).

5.4

Quill Most of the failures that is related to the injection point have occurred immediately downstream of the injection quill. Such failures have been attributed to general corrosion attack of the concentrated product, which attacked the pipe wall prior to the product being diluted by the produced fluids.

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Consequently, the use of internal injection tubes, as quills, atomizing nozzles, etc., which direct the product into the process fluids, is required. 5.4.1

General Quill Design Criteria The design of an injection quill is very critical. The quill should be designed efficiently to disperse injected chemicals into a process stream without allowing the injected chemicals to build up on the interior walls of the pipe and without clogging the injection quill opening. The injection quill must be sized to inject the desired amount of chemical. The injection quill should be capable of injecting the chemical in such way to effectively and intimately mix the chemical with the process stream. Injection quills should be installed per approved design drawings and inspector has to measure the injection quill insertion lengths prior to the installation. The quill design should be evaluated for possible stress, fatigue problems and flow induced vibration. For new projects, stress calculations must be performed and provided by the engineering contractor to determine the optimum injection quill insertion length. These calculations should be reviewed and approved by CSD. For any replacement quills, stress calculations must also be performed and provided. Process stream flow rate fluctuations, flow regimes, fluid viscosity and quill natural frequency are essential variables affecting injection quill design. Natural frequency and wake frequency calculations shall be performed on each quill that will be installed in the field. The purpose of these calculations is to prevent the quill from entering a resonant vibration in which fatigue failure can occur. The wake frequency should be less than 80% of the quill's natural frequency to guarantee no resonant harmonic vibration. This can be determined by applying the thermowell calculations in SAES-J-400 Paragraph 5.3.

5.4.2

Angled Face Quill Design The style of the injection quill with open end shall has a bevel cut angle with 45° as a minimum and 60° as a maximum. Angles less than 45° would limit the influence of the scarf cut. The quill must include a slot through a wall of the quill tip. The slot shall not be longer than the length of the bevel. The slot is rectangular and is opposed to the angled end. The quill with angled face utilizes the turbulence created by its design, in conjunction with the natural turbulence within the pipe, to accomplish distribution of the injected chemical into the process stream. The disadvantage of the quill with angled open end is that at low process Page 15 of 58



stream flow rates there tends to be a concentration of the injected chemical at the pipe wall surface below the injection point. For liquid-phase stream, the quill should be installed in the pipe so that the angled face of the quill faces the fluid downstream (Figure 6). While for mixed and vapor phase streams, the angled face of the quill should face the fluid upstream as shown in Figure 7.

45o-60o

Figure 6 - Proper Quill Alignment in a Liquid-Phase Stream

45o-60o

Figure 7 - Proper Quill Alignment in a Mixed and Vapor Phase Streams The above mentioned design of quill tip is commonly used in upstream facilities and can be used as an option for neutralizing and filming amine injection system in addition to the side hole opening quill. 5.4.3

Caustic Injection Quill Design Caustic Injection quill (Figure 8) shall not be fabricated using pipe with welded end plate. Cracking around a circumferential fillet weld can occur due to the difficulty of getting a sound weld in this restricted area. So, caustic injection quill must be fabricated from solid Monel bar. The design, materials, fabrication, examination, and testing of the fabricated Page 16 of 58



Monel bar shall meet the requirements of ASME B31.3 “Process Piping”. Fabricating the caustic injection quill by boring a solid Monel bar is considered as unlisted components in ASME B31.3. The ASME B31.3 Code defines unlisted components as components not in Tables 326.1, A326.1, or K326.1 of the code. The processes used to fabricate the caustic injection quill must be reviewed for Code compliance. Some fabrication processes can cause gross or local wall thinning. The absolute first stage in the process of fabricating the caustic injection quill is to perform PMI on the bar material to assure that the material is indeed Monel 400. Do not rely on paperwork or bar stamping. The metallurgical condition of the bar should be “annealed” which will give a yield strength in the range 25 to 50 ksi. The machining should be done in more than one pass. First a rough cut is required followed by fine cutting. The objective is to avoid work hardening the surface of the Monel. All machining should be done with adequate lubrication. The quill must be examined in accordance with the ASME B31.3. Dimensions of the fabricated quill shall conform to those of comparable listed components as practicable as possible (straight pipe). In any case, dimensions shall be such as to provide strength and performance equivalent to standard components except as provided in paragraphs 303 and 304 of ASME B31.3. The pressure/temperature design of the fabricated caustic quill shall provide the same safety margins as ASME B31.3. The Code states that the pressure design must meet the requirements of paragraph 304.7.2. The fabricated caustic injection quill may be used provided that it conforms to a published specification or standard within the following limitations: 1)

The designer shall be satisfied that composition, mechanical properties, method of manufacture, and quality control are comparable to the corresponding characteristics of listed components.

2)

Pressure design shall be verified in accordance with paragraph 304 of ASME B31.3.

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The pressure design of the fabricated caustic injection quill shall be based on calculations consistent with the design criteria of ASME B31.3. These calculations shall be substantiated by one or more of the means stated below (paragraph 304.7.2 of ASME B31.3) considering applicable dynamic, thermal, and cyclic effects in paragraphs 301.4 through 301.10 of ASME B31.3, as well as thermal shock. (a)

Extensive, successful service experience under comparable conditions with similarly proportioned components of the same or like material.

(b)

Experimental stress analysis, such as described in the Boiler Pressure Vessel Code, Section VIII, Division 2, Appendix 6.

(c)

Proof test in accordance with either ASME B16.9, MSS SP-97, or Section VIII, Division 1, UG-101.

(d)

Detailed stress analysis (e.g., finite element method) with results evaluated as described in Boiler Pressure Vessel Code, Section VIII, Division 2, Appendix 4, Article 4-1. The basic allowable stress from Table A-1 shall be used in place of Sm in Division 2. At design temperatures in the creep range, additional considerations beyond the scope of Division 2 may be necessary.

(e)

For any of the above, the designer may interpolate between sizes, wall thicknesses, and pressure classes, and may determine analogies among related materials.

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Figure 8 - Caustic Injection Quill Simplified Drawing Page 19 of 58


5.5


Calibration Tube Accurate calibration of chemical injection rate is essential to provide adequate protection to the piping and equipment and to control the chemical consumption. So, the injection system shall include provisions for pump calibration and flow rate verification down stream of the metering pumps. A vented calibration tube (graduated cylinder) in addition to the inline flow meter shall be installed on each chemical injection pump which will provide an easy way to measure the rate of flow of the chemical being injected. While the use of inline flow meters is becoming more common, field installations may inject volumes as low as one gallon per day. The costs of flow metering equipment in these cases exceed the costs for chemical injection. So, the need for inline flow meter may not be required for low volume injection. Tank consumption tracking or graduated cylinder can provide the injection confirmation required in these situations. Flow switches can be installed which shut the pump in on low flow and send an alarm indicating low flow. Flow measurement data and alarms shall be sent to the DCS. A calibration tube is typically a clear tube with markings in milliliters, gallons/hour (GPH) or gallons/day (GPD) as appropriate and used with a stop watch to measure the flow rate. The tube should be placed on the suction side of the injection pump with the necessary valves and fittings so the injection rate can be checked any time by the operator. Main line chemical feed and calibration tube shut off valve shall be ¼ turn ball valves and shall be positioned so that the operator can easily and simultaneously operate both valves during calibration.

Figure 9 - Calibration Tube Drawing

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Below is a simplified procedure in how to use the calibration tube to measure the chemical flow rate:

5.6

1.

With valve A open and the pump operating (Figure 9), open valve B slowly until chemical level reaches the 0 mark.

2.

Close valve A and begin timing with a stopwatch or wristwatch secondhand.

3.

At the one-minute mark, observe the chemical level. This is the actual pump flow rate.

4.

The graduated cylinder should be drained when it is not in use by closing valve B and opening valve A.

Injection Line Injection lines should be sized to allow for the efficient transfer of chemical and stay within the working pressure of the material. All connections from the chemical pump to the point of injection shall be hard piped. Flexible tubing in certain portions can be used only if pressure and temperature limitations are not exceeded. The distance between the chemical storage tank and the injection point should be minimized as much as possible. All piping to the injection pump and from the pump should be free draining towards the pump to avoid any chemical stagnation.

5.7

Check Valve Check valves must be installed on all chemical lines at the inlet line to the injector to prevent the process fluid from pushing back into the chemical injection line. Some of the line or fittings have built-in internal check valve. It is recommended to install external ones. The internal check valves are not reliable in case of internal corrosion that will damage the internal threads causing the check valves to be disoriented and becoming useless. Also, the long inspection intervals of these fittings, once a year during the plant PM shutdown, will make them un-reliable.

5.8

Filter Filters/Y-strainers must be placed between the chemical supply and the injection pump. The size and type of the filter element will depend on the rate and type of fluid that is to be pumped. Two separate filters with individual isolation valves shall be provided where chemical injection can not be stopped for process requirement such as demulsifier.

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5.9


Miscellaneous Most of the chemical injection lines are small in size (less than 1-inch diameter mostly) and they are not rigid, which can vibrates easily if not properly supported. This continuous vibration, even if it was minor, would result in pending fatigue failure in the chemical lines in the long run. As a result, adequate support to these chemical lines must be provided. Each injection point shall be installed with an isolation valve in case any repairs are needed to chemical feed system. For retractable system, vent valve must be installed to release pressure and drain any process fluid/gas that accumulates after the quill is retracted from the process and the injection process valve is closed. A pressure relief valve must be installed on the pump discharge to vent fluid back into the chemical tank or pump suction line if pressure builds up. A pressure gauge for each pump discharge line must be installed. A sight flow indicator is recommended to be provided close to the injection point location as visual indication of chemical flow. A pulsation damper, to ensure an even chemical application, shall be provided in each pump discharge line and shall be sized to provide sufficient degree of damping. As per SAES-L-110 Section 8, seal welding of threaded joints is required when deemed necessary by the Operating Organization for those locations and services where an uncontrolled leakage would result in serious consequences for the operation or safety of plant and personnel. Seal welding of all threaded joints up to the first block valve is required in the following services and applications: ●

All hydrocarbons

●

Boiler feed water, condensate, and steam systems utilizing ASME Class 300 and higher flange ratings

●

Toxic materials such as chlorine, phenol, hydrogen sulphide, etc.

●

Corrosive materials such as acid, caustic, etc.

●

Oilfield chemicals (e.g., corrosion inhibitors, Demulsifiers, electrolytes, etc.)

●

Piping which is subject to vibration, whether continuous or intermittent

As per SAES-A-206 Section 5 and 00-SAIP-007, PMI testing shall be performed at a point in time that ensures proper alloy materials have been used Page 22 of 58



in the fabrication of an identifiable assembly. Usually, this is done after fabrication and immediately prior to fabrication to ensure completes testing of the injection system components before their installation in the field. The following information is needed to design an optimum injection system: ●

System Parameters

●

Chemical Parameters

6

Pipe/vessel diameter (also vessel length if applicable) Line pressure Fluid viscosity Fluid density Mass or volumetric flow rate Working temperature Clearance for the retrieval of the quills

Viscosity Density Temperature Anticipated injection pressure Mass or volumetric flow rate Concentration of active ingredient

Chemical Injection Point Position The injection point is installed through an opening in the wall of the pipeline. It should be installed in location which can be accessed by the Operations. Adequate clearance shall be available for insertion and removal of the quill. The effectiveness of the chemical injection is heavily influenced by the location of the injection point. The quill should be installed in pipe provided, of course, a sufficient flow rate to promote distribution of the chemical solution. The turbulent flow at the injection point should cause mixing of the injected chemical with the process stream. The relative viscosity of injected chemical and the process stream play a major role in mixing. The injection tube tip shall be inserted within the center 1/3 of the pipe as shown in Figure 10 that illustrates a side view of the chemical injector installed in a pipeline. Generally, the most effective position for chemical injection is at the center of the pipe. Highest fluid velocity is normally at the center of the line, therefore, injection at this point is supposed to prevent concentration of the chemical at the edge where the Page 23 of 58



velocity is low due to friction and will ensure efficient distribution of the introduced chemical. It is imperative that any injected chemical is not directed at the equipment wall where it could cause local corrosion attack and wall perforation. In large diameter systems, it may be impossible to find a quill that can be either retractable or retrievable. Therefore, for nominal line sizes of 36 inches and greater, insertion quill length shall provide a tip location not greater than 35% of the nominal diameter measured from the out side wall of the pipe while the minimum insertion must be no less than 6 inches. If the line pipes are designed for regular scraping operations, protruding injection quill must be removed before scraping begins. Installation of the protruding chemical injection tubes in the scrapable line can be avoided by locating the injection point at other locations such as lateral lines, etc.

Injection Tube

See Note Proper insertion depth shall be within center 1/3 of the pipe

Note: the most effective position for chemical injection is at the center of the pipe

Figure 10 - Quill Insertion Limits The quill opening must be aligned parallel to the process flow with the correct opening orientation, as illustrated in the previous section, when the injection tube assembly is placed in the process pipe. Therefore, the orientation of the quill must be marked to insure proper positioning of the quill opening once the injection tube assembly is installed in the process pipe. One of the recommended field practices, for high pressure injection system, is to permanently mark, on the solid plug hex nut, the long side of the quill with a straight line using a file, small hacksaw cut or waterproof paint marker. This convention should be maintained if possible whenever the quill is reinstalled. The solid plug should not be loosened in order to achieve orientation, as this may affect the plug seal in the access fitting. This shall be part of an installation checklist signed off by the installer and assigned inspector. Page 24 of 58


7


Chemical Injection System Inspection Monitoring and inspection are key activities in maintaining chemical injection system integrity. Chemical injection systems must be inspected regularly, including the injection point itself, downstream and upstream piping and equipment that may have been affected. Inspection frequencies should be determined by the type of mechanical/ physical deterioration anticipated. The inspection frequency shall follow SAEP-20, paragraph 5.5.6.3. The NDT inspection shall be performed every three month for the new installed quills and after T&I installation for the first year. The need for more detailed inspection requirements for chemical injection system was formally addressed industry-wide with the issuance of API RP 570 “Piping Inspection Code Inspection, Repair, Alteration, and Rerating of In-Service Piping Systems”. As stated in API RP 570, injection points are sometimes subject to accelerated or localized corrosion from normal or abnormal operating conditions. So, API RP 570 recommends more rigorous inspection of injection points due to the potential susceptibility to accelerated or localized corrosion and these areas need to be inspected thoroughly on a regular schedule. Moreover, inspection requirements can be found in 01-SAIP-04 “Injection Point Inspection Program”. This Saudi Aramco inspection procedure provides guidelines to plant personnel on the injection point's identification, tracking and monitoring. Refer to 01-SAIP-04 for more details.

8

Management of Change The Management of Change (MOC) process shall be used to identify changes which could impact the inspection plan for a particular injection point circuit. Changes to the composition of the additive, location of the injection, and length of time the additive is injected can occur frequently. This is especially important when a trial program for an additive is initiated. Close communication between Operations, Engineering, and Inspection personnel regarding these types of changes will help prevent the development of problems due to an oversight in the inspection program. In addition, the same type of communication on new installations will help improve the effectiveness and minimize the cost impact of the inspection program by addressing key issues such as materials selection, inspection access, and potential corrosion problems. A detailed review of the methodology involved in performing an effective MOC is beyond the scope of this best practice. Below are some examples of work/changes requiring MOC approval: ●

Use of different chemicals

●

Change of chemical Manufacturer

●

Process parameters Page 25 of 58



●


●

Locations of the injection point

●

Routing chemicals to any sewer

●

New chemicals being introduced

●

Existing chemicals being mixed in different ways

●

Quill replacement in kind to ensure updated construction drawings.

The success of the program depends on timely communication of changes made to injection systems. Ideally any change in chemical type, injection rate, duration, injection location or concentration should signal a need to analyze potential impact on the inspection program. 9

Chemical Injection System Maintenance The proper assembly and care of a chemical injection system is extremely important. Establishing and following a thorough maintenance routine will aid in preventing any problems. To ensure maximum performance, periodic checks and cleaning are necessary for the injection quill. This cleaning practice can be done during the plant shutdown. All tubing connections, fittings, tanks, and pumps should be checked by the plant operators on a daily basis. The injection fittings must be examined regularly for leaks and thread damage. Injection fittings should be thoroughly cleaned at least once a year. Installed filters should be disassembled, cleaned, and inspected on a regular basis for contamination and damage. The frequency of inspection is dependent upon the fluid injection rates; the higher the rates, the shorter the time between inspections. Filter elements should be replaced if there are any signs of plugging or contamination. The filter element can be flushed from the inside out with solvent. If any significant debris is noted at any one time, the source must be identified and eliminated. The check valve should be checked regularly to confirm that its seat is clean and seated correctly to stop any back flow. If a chemical injection system appears to be plugged or the flow restricted, stop injecting immediately. Pull and inspect the filters for debris. If the injection system does not respond to this treatment, stop pumping. Troubleshoot the chemical injection system to identify the location of plugging and clean it. Continued pumping may only increase the severity of the problem and possibly damage the system. If any piping or equipment shuts down or is taken down for inspection or maintenance, the chemical injection system related to this piping or equipment shall be stopped. This will avoid concentration of the injected chemical at the injection site which can lead to corrosion for the pumps, valves and piping system. Page 26 of 58



If the chemical pump is to be stopped for an extended period in excess of 2 months, it is recommended that the original chemical be displaced from the injection system by flushing with an appropriate solvent. Stagnant chemical lying in the injection system could cause plugging, and corrosion. Selection of solvent will be determined on a case by case basis. Contact CSD/ME&CCD Corrosion Technology Unit for further guidance. Proper mothballing of the chemical system including tanks and pumps shall be considered based on the downtime period defined in Saudi Aramco Mothball Manual (SAER-2365). This manual provides basic guidelines and recommendations for the preparation of detailed procedures for mothballing piping and equipment. If polymerization of a chemical is a problem when the system is suspended, then the line shall be provided with drainage capability and the line drained immediately following suspension of service. This shall be clearly stated in the OIM for the system. The injection point isolation valve must not be closed without stopping the pumps, because injection against a closed injection location valve will cause continual operation of the PZV. Records of maintenance activities, repairs and downtime for the chemical injection system should be documented to develop appropriate maintenance strategies. 10

Injection Point Documentation The injection system details shall be documented, including: ●

Process operating window

●

Anticipated conditions

●

Equipment design

●


●

Monitoring requirements

●

Inspection requirements

Appendix A contains a sample form that can be used for documenting plant injection point details. This form should be carefully filled out completely with as much detailed information as possible for each injection point in the plant. It will help concerned engineers/inspectors to make sure that all injection points are included in the inspection program. This form will assist plant inspector to select the proper inspection techniques and to optimize the inspection interval. For caustic, neutralizing and filming amine injection points, all PMI performed must be documented and logged in inspection files. Proved quill tip location and orientation after installation and before startup by radiography shall be also retained by the plant inspection. It is recommended that a digital photograph before installation to be taken Page 27 of 58



for the quill tube inserted in the pipe so that the conditions and details of the quill can be noted. This photograph should be documented in inspection files. 11

Safety The purpose of warnings and cautions highlighted below is to call the operator’s attention to possible danger of injury to personnel and/or damage to equipment, and deserve careful attention and understanding. Safety precautions must be established throughout any activities related to the chemical injection system operations including, but not limited to the following: ●

Safe operation for the retrieval equipment requires a minimum of two (2) trained operators.

●

The retrieval equipment shall not be used unless the crew performing the work has been trained in its safe operation.

●

All plant safety requirements and environmental regulations shall be followed.

●

The media type, its pressure and temperature for the attended job shall be identified before commencing the job.

●

All the required personal protective equipment shall be provided and used when checking the injector, i.e. hard hat, safety glasses, protective clothing, face shield, safety gloves, breathing apparatus, etc.

●

Any actions which could vary system pressure such as surges caused by opening and closing of valves and chokes should be delayed until completion of the attended job related to the chemical injection system operations.

●

Enough clearance for safe operation around the attended location should be established.

●

Wind direction prior to starting operations involving hazardous products should be noticed.

●

Up-to-date CHBs shall be posted near all chemical storage tanks and unloading sites.

●

Ensure safe release of chemical to the environment by proper installation of equipment, provision of ventilation and personnel protection.

●

Every chemical injection skid shall be equipped with eye washes and showers side to be used in case of any emergencies situation.

●

Waste chemical shall be disposed in a safe place.

●

For the retractable injector, be careful when breaking connections. Release the pressure on the chemical line using the drain valve on the pump discharge. Be sure to close the isolating valve on the process before inspecting the retractable injector. Break the connection between the retractable injector and the isolating valve slowly Page 28 of 58



and carefully to release any pressure. Verify that the valve is completely shut and holding before removing the retractable injector. Never operate the retractable injector without the external support frame. ●

The operator should always position himself to the side when working on the injector location.

The following sections (12, 13 and 14) describe the details of chemical and water wash injection requirements in Saudi Aramco facilities with respect to design basis, injection locations, and material of construction. 12

Refinery Chemicals and Water Wash Injection Many different types of process additives are used to maintain reliability and optimal performance of refinery operations. The types of injection chemicals used in refineries are as varied as the intent and purpose of the programs they service. An additive can be either a commodity chemical such as acid, caustic, methanol; or a proprietary chemical such as neutralizing amine, filming amine, antifoulant and chloride. The additive can be as simple as a water stream injected to dissolve salt deposits or to dilute corrosive process components. Some of the major types of additives used in refineries are: 12.1

Caustic Addition in Crude Units Caustic (NaOH) injection is used to reduce crude column overhead acid corrosion, caused by hydrogen chloride (HCl). Caustic is injected at one or two points in a Crude Unit. Caustic may be injected upstream of the desalters but it is not recommended. It should be noted that, pH above 7.0 leads to tighter emulsions and poor performance of the desalters while pH below 7 is better for the desalter performance. Additionally, it is injected at a location between the desalter and the fired heaters. The location of this second injection point varies from refinery to refinery in Saudi Aramco’s operations. It may be injected immediately downstream of the desalter or immediately upstream of the heaters. 12.1.1

Design Basis The design is based on injecting up to 5 lb of NaOH (100%) per 1000 bbl of crude in the form of a 3 wt % aqueous caustic solution mixed with sufficient bypassed crude to maintain an injection velocity of 30 ft/sec, as a minimum for good mixing, into the main crude stream. The following minimum velocities should be considered when a caustic injection system is designed: Caustic Injection Orifice Velocity, ft/sec Slipstream Injection Orifice Velocity, ft/sec Crude Velocity in Main Stream, ft/sec

20 20 7 Page 29 of 58


12.1.2


Injection Locations ●

Downstream of the Desalter Caustic injection downstream of the desalter is an effective method to reduce overhead corrosion. Caustic injected at this location must be thoroughly mixed with the crude stream. This is best achieved by use of a crude slip stream and static mixer. The crude slip stream should preferably be obtained from a location after the desalter to eliminate undesalted crude from being reinjected into the stream. In some cases, injection into the crude pump suction has had an equally effective mixing role as using a slip stream. Inadequate mixing can result in excessive fouling of heat exchanger trains. Caustic is usually injected at a low concentration, on the order of 1 to 5 weight percent (2 to 7 oBaume). This low concentration requires a greater volume and aids in effective mixing with the crude stream. The injection of a low concentration also reduces the risk of caustic corrosion and caustic stress corrosion cracking. In order to minimize fouling of the heat exchangers, it is critical that caustic quality be strictly controlled. At refineries where there are large fluctuations in caustic quality, heat exchanger fouling and caustic stress corrosion cracking have occurred. Piping and equipment downstream of the injection location must be post weld heat treated (PWHT) to minimize the risk of caustic stress corrosion cracking. However, even PWHT pipework is not immune from cracking in high concentration caustic streams. A Monel 400 quill is required for caustic injection at this location. Such quills have an expected service life well in excess of ten years. The measured chloride content in the overhead accumulator water controls caustic addition downstream of the desalters. The target range is 10-30 ppm Cl- in the accumulator water. Currently, at most Saudi Aramco refineries, operators adjust the caustic rate when a chloride reading is out of specified limits. However, the injection rate is usually limited to a maximum of 2 PTB (pounds per thousand barrels) to prevent downstream fouling.

●

Upstream of the Heater Caustic injection upstream of crude heater is an alternative if and only if heat exchangers downstream of the desalter experience Page 30 of 58



severe fouling. However, there are increased risks from caustic injection at these higher temperatures. For contrast, Shell’s Best Practice specifically requires caustic injection at temperatures less than 350°F. Nalco’s Best Practice limits caustic injection to a temperature of less than 300°F. Caustic at elevated temperatures is extremely corrosive and can corrode the injection quill or the pipe wall itself if the quill is incorrectly positioned. Further, caustic may cause caustic stress corrosion cracking of non-stress relieved pipework and heater tubes. Injection of caustic at this location requires precision engineering and operation. Caustic of consistent strength and quality must be thoroughly pre-mixed with a slip stream of crude, ensuring thorough mixing with the use of a static mixer. Injection is achieved via Monel 400 pipework, valves, and quill. The crude slipstream must be carefully monitored to ensure that the caustic stream is not injected un-mixed into the main crude line. The Monel 400 quill will experience some minor sulfidation on the process side at these temperatures, in the region of very approximately, 500°F. 12.1.3

Crude Bypass Stream The most important consideration in the design of the crude bypass stream is to establish a controlled flow which will maintain an injection velocity of 30 ft/sec into the main crude stream. [It is assumed that the velocity of the main crude stream at the point of injection will normally be greater than 7 ft/sec]. In order to meet this objective, while at the same time limiting the bypassed crude rate to less than 1% of the maximum expected crude rate, three differently sized injection sections, as shown in Table 2, are recommended to cover the range of crude unit capacities: Table 2 - Crude Unit Charge Rate vs. the Slipstream Rate Maximum Expected Crude Rate at 600°F, BPD

Bypass Rate at 300°F, BPD (GPM)

Over 100,000

940 (27)

60,000-l00,000

580 (17)

Under 60,000

300 (9)

It is obviously important to stop injecting caustic during crude flow interruptions to avoid formation of a pool of concentrated caustic in the carbon steel system. It is, therefore, strongly recommended that a low

Page 31 of 58



flow shutdown be installed to stop the caustic pump when the bypassed crude rate decreases to less, than 85% of its design rate. 12.1.4

Requirements for Caustic Injection System The detailed design of the caustic injection system is shown in the Library Drawing # DB-950177. Table-3 summarizes the caustic injection requirements. Refinery must have current as-built quill detailed design drawings which also specify the quill materials of construction. These drawings should be up-to-date and signed-off. Table 3 - Caustic Injection Requirements

Variable/Location

Target or Limit

Comment

Source

Fresh caustic only

Spent caustic results in tramp compounds entering the system and causing corrosion, fouling, emulsions, and foaming.

Caustic concentration

1 to 5 wt % (2 to 7o Baume)

Typical values. Dilute caustic aids mixing. Identical concentration must be provided. Variation in caustic strength injected to process stream is a major cause of preheater fouling.

Measurement

Each batch

Essential. Measure the concentration of each and every batch of caustic to be used in the plant prior to use. Data must be stored in a permanent record. Injection of offspecification caustic at one plant caused stress corrosion cracking and an economic loss of over $1 million. Injection of off-specification caustic at another plant caused excess fouling.

Dilution water O2

< 20 ppb

Stripped sour water is a good source.

Dilution water Cl-

Zero

Target. Target. The larger the better to minimize batch make-up operation and variation. Nitrogen blanket to exclude oxygen.

Storage tank

Mechanical mixers.

Caustic delivery to unit

Injection location

Dedicated line

Strongly preferred. A dedicated line from the bulk caustic tank to the unit day tank facilitates the correct dilution of caustic. At least two plants that use a complex caustic header system have experienced major problems with cross contamination and delivery of out-of-specification caustic that resulted in major operational problems. NACE recommends and 80% of the industry injects caustic downstream of the desalter. The suction of the crude booster pump is the normal location and assists efficient caustic mixing. In cases where preheater fouling is an issue, then caustic injection upstream of the heater is allowable. Ras Tanura Plant 15 has had good long term success with this latter methodology.

Page 32 of 58

Document Responsibility: Materials and Corrosion Control Issue Date: 1 July 2007 Next Planned Update: TBD Variable/Location

Injection temperature

Target or Limit

Maximum 350°F

Salt < 2 PTB, add 1 PTB NaOH Quantity injected

Salt 2-5 PTB, add 1.5 - 2 PTB NaOH Maximum 2 PTB

SABP-A-015 Chemical Injection Systems Comment

Best practice of the majority of the industry. Shell restricts caustic injection temperature to 350°F. Nalco’s Best Practice restricts caustic injection to 300°F. Higher temperatures can be used but only if fouling of preheat exchangers or some other site specific need makes it essential. Fouling can be readily detected by measurement of pressure drop across the preheater. Higher temperature injection requires careful and continuing attention to every detail as failures at higher temperatures can be catastrophic. Caustic injection rates are fine tuned based on overhead chloride levels. Initial rates for a new unit follow the rules of thumb provided. The maximum amount injected is limited to less than 2 PTB NaOH. Amounts injected may be limited further due to effects on downstream process such Visbreakers, FCCUs, and hydrocrackers.

Monel 400

Saudi Aramco experience has demonstrated that this material serves well whether the injection point is located downstream of the desalter or upstream of the heater.

Only when the unit is down

The caustic injection quill can be removed only when the unit is down. The quill must be inspected at every T&I.

PMI

Positive Material Identification of the injection quill must be performed on site on all quill fittings to verify metallurgy upon the removal. This must be documented and logged in inspection files.

NDT

Visual inspection supplemented by Magnetic particle testing or penetrant testing should be conducted by the plant inspection to determine the need for replacement. Ultrasonic Thickness measurement should be taken on all quill fittings. The retirement thickness (Tmin) of the quill should be calculated by the Inspection Department in cooperation with the refinery Corrosion Engineer.

Injection quill must be the correct length

Field verification of pipe diameter and quill length to be confirmed before installation by operations, process engineer, inspection and maintenance.

Dilute caustic mixed 1:100 with crude slip stream

Use of a slip stream aids dispersion of the caustic and helps to minimize caustic-caused corrosion problems. The slip stream is effectively mixed prior to injection using a Monel 400 static mixer. All caustic pipe and fittings shall be Monel 400.

Installation of a flowmeter

The slip stream line should be fitted with a flowmeter for positive flow indication and appropriate restriction orifice.

Static mixer

Static mixer shall be used to ensure a homogenous mixture.

Monel 400

Use Monel 400 only.

Injection orientation

Co-current with crude flow

The quill should be installed in the pipe so that the hole of the quill faces the fluid downstream (Figure 8).

Quill construction

PMI

Shop QA/QC inspector must identify all materials to be Monel 400 during fabrication. The PMI Results must be documented and compared to the approved site drawings.

Injection quill material

Injection quill removal

Injection quill length

Injection slip stream

In-line Mixer

Page 33 of 58


Target or Limit


Welding procedure

A special welding procedure should be verified by CSD welding engineers.

PMI

Positive Materials Identification of the injection quill and all slip stream pipe and fittings must be performed on site to verify metallurgy. Material other than Monel 400 shall not be fitted.

Radiography

Location of quill tip shall be proved after installation and before startup by radiography. A permanent record of the radiograph shall be retained by the refinery.

Non-retractable with match-mark indicator

Correct positioning of the quill is critical. Therefore, a nonretractable design shall be used. A match-mark indicator is used to show the orientation of the quill opening.

Minimum schedule 80

The quill must be schedule 80 and/or thicker.

Latest revision available

Drawings update / redlined and approved by CSD should be archived and new drawings communicated to all affected refinery personnel.

Crude pipework upstream of the injection point

PWHT for minimum of 3 diameters upstream

Required that the pipework, fittings, etc., be post weld heat treated to prevent caustic stress corrosion cracking. Failures due to Caustic SCC have occurred in Saudi Aramco plants.

Crude pipework downstream of the injection point

PWHT all piping systems and equipment.

Required that the pipework, fittings, etc., be post weld heat treated to prevent caustic stress corrosion cracking. Failures due to Caustic SCC have occurred in Saudi Aramco plants.

Crude pipework inspection

NDT

The pipework upstream and downstream of the injection location must be inspected as per API RP 570 and 01SAIP-04 for injection point. The frequency of NDT inspection shall be increased to every three months for newly installed quills for the first year of operation.

Operating procedures

Caustic injection rate

As communicated by the operation engineer on a daily basis and any deviations reported in RSS report.

Quill installation

Quill design

12.2

Neutralizing Amine in Crude Units Neutralizing amine is introduced into the crude unit overhead lines from the atmospheric columns and vacuum columns to neutralize the acids that cause very low pH and high corrosion rates at the water dew point. The objective of injecting neutralizing amine is to control the pH in the overhead receiver water at a pH of 5.5 to 6.5 which is the range commonly used in the industry. However, some companies have adopted different ranges. Chevron uses a target range of 7.5-8.0. This higher pH is achievable in systems using ammonia for neutralization but is not cost effective in Saudi Aramco systems where a neutralizing amine is used. 12.2.1

Design Basis The neutralizing amine should be injected through an injection quill Page 34 of 58



with steam to distribute and atomize the neutralizing chemical. This method will fully disperse the neutralizer into the vapor stream and will prevent neat chemical injection which could lead to under-deposit and severe localized corrosion. In order to have a good neutralizing amine injection the following items shall be consider in the system design:

12.2.2

●

All process-wetted parts, including the injector pipe with a quill tip or nozzle, are constructed of Hastelloy C2000, B-2 or Inconel 625.

●

The steam pressure should be in the range of 50 to 150 PSI.

●

The steam should be trapped and filtered close to the injection point.

●

The steam injector equipment, valves and check valves in steam side service should be rated for this service with steam.

●

The neutralizer mixing tee should be as close to the injector as possible.

●

The mixing tee should be horizontal to or above the top of the injection pipe to insure free uniform flow of the neutralizer.

●

The neutralizer mixing tee and the chemical and steam lines should be supported on adjacent structures to avoid placing excessive strain on the chemical injector pipe and packing gland.

●

Both the steam line and the neutralizer line shall have a check valve to insure proper flow.

●

Both the steam line and the neutralizer line should have a filter (Y-strainer – 100 mesh) located near the steam injector to prevent mill scale or other solid contaminates from fouling the injector pipe or nozzle.

●

The steam injector should be installed in the top or side of the horizontal section of overhead vapor line, not the bottom.

●

Using 316 stainless steel materials or better for the steam and neutralizer line to the steam injector is recommended.

Injection Locations The neutralizer should be injected into of the crude column overhead vapor line before any salts can form, and before any water can condense. The neutralizing amine injection point should be located near the top of the crude unit overhead line after the first elbow.

Page 35 of 58


12.2.3


Requirements for Neutralizing Amine Injection System The detailed design of neutralizing amine injection system is shown in the Library Drawing # DB-950178. Table-4 summarizes the neutralizing amine injection requirements. Refinery must have current as-built quill detailed design drawings which also specify the quill materials of construction. These drawings should be up-to-date and signed-off.

Table 4 - Neutralizing Amine Injection Requirements Variable /Location

Target or Limit

Comment

Filter

Y-Strainer

Preferred. 100 mesh typical. The Y-Strainer should be installed in both the steam line and neutralizer line immediately before mixing, but at a location that can easily be serviced (easily accessible from an existing platform). This will reduce the problem with quill blockage by preventing mill scale or other solid contaminates from fouling the injector pipe or nozzle.

Treatment rate

Enough to maintain pH in the Overhead receiver from 5.5 to 6.5

Treatment rate is adjusted to give the required overhead receiver pH. The Nalco Strong Acid Test provides a method to calculate the target injection rate that will assure neutralization of the first drops of condensing acid.

After 1st elbow

Neutralizer must be injected into the overhead system. Injection into the reflux is bad practice. For crude unit, preferred location is immediately downstream of the first elbow if the outlet pipe is installed at the top of the crude column.

> 5 pipe diameters from downstream elbow.

Strongly preferred to achieve proper mixing and to avoid erosion-corrosion on downstream elbow.

Co-injection with wash water

Neutralizer co-injection with the wash water without nd steam (downstream of the 2 elbow) can be considered as an alternative on a case by case basis with approval of CSD.

Injection location


Mixing Tee

Steam co-injection

Injection point with steam to be top side of line if entering on a horizontal portion of line. Co-current with the process stream flow.

The quill should be installed in the pipe so that the hole of the quill faces the fluid downstream.

The mixing tee should be as close to the injector as possible.

Mixing Tee should be located at an elevation above the injection point. The mixing tee should be horizontal to or above the top of the injection pipe to insure free uniform flow of the neutralizer.

The steam used should be from 50 psi to 150 psi.

Required. Use steam co-injection to ensure neutralizer is vaporized and adequately dispersed. Use lowest pressure steam that meets design need. Inject into the overhead at no more than 5 psi over stream pressure. The steam should be trapped and filtered close to the injection point.

Page 36 of 58

Document Responsibility: Materials and Corrosion Control Issue Date: 1 July 2007 Next Planned Update: TBD Variable /Location

Target or Limit


Installation of a flowmeter

The slip stream line should be fitted with a flowmeter for positive flow indication and appropriate restriction orifice.

Steam injector equipment, valves and check valves in steam side service

Should be rated for this service with steam.

Steam and neutralizer lines and fittings metallurgy

Piping from and including the mix point with steam shall be a compatible material.

Using 316L stainless steel or better tubing material is recommended. This tubing is clean and more resistant to corrosion than mild steel that is commonly used. Monel shall not be used for inhibitor service.

Steam trap

Should be installed on steam line close to the mixing point

Quill design

Retractable

Mandatory. Allows maintenance on-stream.

12 o’clock

Normal orientation.

Inject in center 1/3 of the stream

Preferred to inject in the center of the stream to ensure even distribution away from pipe walls. In large systems it may be impossible to obtain a quill that can be retractable, i.e., removed on-line and meet this criteria. In this case, the minimum insertion into the pipe flow must be no less than 6 inches.


Injection quills must be the correct length. Field verification of pipe diameter and quill length to be confirmed before installation by operations, process engineer, inspection and maintenance.

Hastelloy C-2000, B-2 or Inconel 625.

Nalco provide Hastelloy C-2000 quills. Hastelloy B-2 that was supplied previously is also a good choice. Monel shall not be used for inhibitor service. Any existing stainless steel quills should be replaced at the next T&I.

PMI

Positive Materials Identification of the injection quill must be performed on site to verify metallurgy.

Central with the pipework

Location of quill tip shall be proved after installation and before startup by radiography. A permanent record of the radiograph shall be retained by the plant.

Quill metallurgy

Quill installation

12.3

Filming Amine (Corrosion Inhibitor) (Crude Unit, Fractionation Columns at Rheniformers and Visbreaker; and Debutanizer at Hydrocracker) Filming amine is added to provide a protective film, or barrier, between the metal surface and the corrosive liquids in the overhead system. Injection rates are typically set to add the filmer at 3-5 ppm based on total overhead naphtha rate. Filming amine should normally not be injected in concentrated form. The product is injected into the overhead line through a quill with a naphtha slipstream with a dilution between 50 and 100 naphtha to 1 inhibitor. Typically, naphtha dilution is provided to help the dispersion, at the Page 37 of 58



injection point, and to dilute the concentrated filming amine that may be corrosive to injection equipment. 12.3.1

Design Basis The filming amine shall be injected through an injection quill with naphtha to distribute the filming chemical. This method will fully disperse the filming amine into the overhead stream and will prevent neat chemical injection which can be corrosive at elevated temperature. In order to have a good filming amine injection the following items shall be consider in the system design:

12.3.2

●

All process-wetted parts, including the injector pipe with a quill tip or nozzle, are constructed of Hastelloy C2000, B-2 or Inconel 625.

●

The filming amine mixing tee should be as close to the injector as possible.

●

The mixing tee should be horizontal to or above the top of the injection pipe to insure free uniform flow of the filming amine.

●

The filming amine mixing tee and the chemical and naphtha lines should be supported on adjacent structures to avoid placing excessive strain on the chemical injector pipe and packing gland.

●

Both the naphtha line and the filming amine line shall have a check valve to insure proper flow.

●

The Y-Strainer must be installed in the naphtha slip stream line and it is preferred for the filming amine line. The Y-Strainer shall be located near the injector to prevent mill scale or other solid contaminates from fouling the injector pipe or nozzle.

●

The injector should be installed in the top or side of the horizontal section of overhead line, not the bottom.

●

Using 316 stainless steel materials or better for the naphtha and filming amine line to the injector is recommended.

Injection Locations The filming amine will typically be injected at several other locations in addition to the crude unit over head including but not limited to: ●

Fractionation Columns at Rheniformers

●

Fractionation Columns at Visbreaker

●

Debutanizer at Hydrocracker Page 38 of 58



For crude units, the filming amine is typically injected immediately downstream of the neutralizer separated by minimum space of 5D if possible. However, Ras Tanura Refinery injects filming amine upstream of fin fans. 12.3.3

Requirements for Filming Amine Injection System The detailed design of filming amine injection system is shown in the Library Drawing # DB-950179. Table-5 summarizes the filming amine injection requirements. Refinery must have current as-built quill detailed design drawings which also specify the quill materials of construction. These drawings should be up-to-date and signed-off.

Table 5 - Corrosion Inhibitor Injection Requirements for Crude Unit Atmospheric Tower Overhead Variable /Location

Target or Limit

Comment

Y-Strainer

The Y-Strainer must be installed in the naphtha slip stream line and it is preferred for the filming amine line. The Y-Strainer should be installed immediately before mixing, but at a location that it can easily be serviced, that is, easily accessible from an existing platform. This will reduce the problem with quill blockage by preventing mill scale or other solid contaminates from fouling the injector pipe or nozzle.

Corrosion Inhibitor Type

Oil dispersible film former

Typical. Presently used in all Saudi Aramco crude unites. An option is to evaluate water soluble products co-injected with the water wash with the approval of CSD and SARCOP.

Injection rate

3 to 5 ppmv of total naphtha product and naphtha reflux.

Typical for normal operations. Depends on product used.

After 1st elbow

Typical. Most Saudi Aramco crude units inject corrosion inhibitor downstream of the 1st elbow, if the outlet pipe is installed at the top of the crude column, and downstream of the neutralizing amine injection point. Ras Tanura primary injection point is at the fin fans. Secondary injection at the fin fans may be appropriate for refineries with flow distribution problems.

> 5 pipe diameters from neutralizer injection

Rule-of-thumb (if possible).

> 5 pipe diameters from downstream elbow.

Strongly preferred to achieve proper mixing and to avoid erosion-corrosion on downstream elbow (if possible).

100 naphtha to 1 inhibitor

Dilute inhibitor in naphtha stream. Flow measurement on inhibitor and naphtha streams essential. 100 mesh screen required. The naphtha stream can be taken from the reflux or other similar source.

Filter

Injection location

Slip stream

Page 39 of 58


Chemical Injection Systems

Target or Limit Installation of a flowmeter


SABP-A-015

Comment The slip stream line should be fitted with a flowmeter for positive flow indication and appropriate restriction orifice.

Injection point with naphtha to be top side of line if entering on a horizontal portion of line. Co-current with the process stream flow

The quill should be installed in the pipe so that the hole of the quill faces the fluid downstream.

Mixing Tee

The mixing tee should be as close to the injector as possible.

Mixing Tee should be located at an elevation above the injection point. The mixing tee should be horizontal to or above the top of the injection pipe to insure free uniform flow of the neutralizer.

Naphtha and filming amine lines and fittings metallurgy

Piping from and including the mix point with naphtha shall be a compatible material

Using 316L stainless steel or better tubing material is recommended. This tubing is clean and more resistant to corrosion than mild steel that is commonly used. Monel shall not be used for inhibitor service.

Retractable


Quill design

Quill metallurgy

12 o’clock

Normal orientation.





Hastelloy C-2000, B-2 or Inconel 625.

Nalco provide Hastelloy C-2000 quills. Hastelloy B-2 that was supplied previously is also a good choice. Monel shall not be used for inhibitor service. Any existing stainless steel quills should be replaced at the next T&I.

PMI

Positive Materials Identification of the injection quill must be performed on site to verify metallurgy.

Central with the pipework

Location of quill tip shall be proved after installation and before startup by radiography. A permanent record of the radiograph will be retained by the refinery.

Quill installation

12.4

Water Wash in Refining Units Water washing has been practiced in many refinery process units as a means of preventing formation or removing fouling salt deposits and to dilute corrosives, often in column overhead systems, hydrotreater reactor effluent systems, and in the overhead of some fractionators.

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12.4.1


Design Basis for Water Wash Rates Most water washes have been continuous. Intermittent washing has been used in some applications for periodic removal of salt deposits. Low water wash rates can be more harmful than beneficial. The water rate must be high enough so that the bulk of the water does not flash at system conditions when injected. Because many of the salt deposits encountered in refining processes are hygroscopic, inadequate water washing can lead to severe localized corrosion in certain circumstances. The water wash rate must be sufficient to maintain at least 25% of the total water injected as liquid water. Typically, for a crude unit overhead, a wash water rate of 4 to 6% of total naphtha stream volume is needed to meet this 25% liquid water requirement.

12.4.2

Injection Locations Many refinery process unites have used water wash as a corrosion control method. The following are list of the water wash injection locations which are: ●

Crude unit atmospheric column overhead piping system Water is usually injected in the overhead piping to help quench and scrub the overhead vapors, dilute acids formed, and keep any salts or acids from accumulating in the system.

●

Hydroprocessing unit reactor effluent cooling trains Ammonia and hydrogen sulfide gases, generated during hydrotreating, combine to form ammonium bisulfide salts as the reactor effluent stream cools down. To prevent plugging of exchanger tubes, water is injected upstream of the salt formation temperature (upstream of the effluent coolers) to remove ammonium chloride or ammonium bisulfide deposits and to dilute aqueous condensates containing these salts.

●

Catalytic reforming unit The typical injection point has been located upstream from the point in the pretreater reactor feed/effluent exchangers where the temperature allows deposition of ammonium chloride. Water is injected on a continuous or intermittent basis to remove accumulations of ammonium chloride salts.

Page 41 of 58

Document Responsibility: Materials and Corrosion Control Issue Date: 1 July 2007 Next Planned Update: TBD ●


Fluid catalytic cracking unit (FCCU) light ends recovery unit Water wash is typically injected upstream of the fractionators overhead condenser and upstream of interstage cooler to reduce corrosion by dilution of the contaminants, such as hydrogen sulfide, ammonia, and cyanide. Conditions in FCCU light ends recovery units have been conducive to hydrogen blistering, hydrogen induced cracking (HIC) and stress-oriented hydrogen induced cracking (SOHIC) problems due to the hydrogen sulfide, ammonia, and cyanide formed by the catalytic cracking reaction.

12.4.3

Requirements for Water Wash Injection System The detailed design of the water wash injection system is shown in the Library Drawing # DB-950176. Table-6 summarizes the water wash injection requirements. Refinery must have current as-built quill detailed design drawings which also specify the quill materials of construction. These drawings should be up-to-date and signed-off. Table 6 - Water Wash Injection Requirements for Crude Unit Atmospheric Tower Overhead

Variable/Location Source

Target or Limit Overhead receiver.

Recycle water from the overhead receiver is the most common source.

O2 <20 ppb

Required. Oxygen in wash water results in major corrosion damage.

TDS

Total dissolve solids (TDS) typically are in the region of 160 ppm in Saudi Aramco operations. Low figures are preferable but not controllable.

Tramp amines

Avoid the presence of tramp neutralizing amines if at all possible. Neutralizers introduced with the wash water help to control overhead receiver pH but do not help control pH in the first condensing drops of acid in the overhead, if condensation occurs upstream of the water wash.

Should be based on dew point location/deposit forming location

For Crude unit: Preferred location is immediately downstream of the second elbow after the crude column if the outlet pipe is installed at the top of the crude column.

5 % volume of overhead naphtha

Target is to maintain at least 25% of the injected water in the liquid phase after injection, so that solids may be washed through the system and the condensing hydrochloric acid diluted. This water wash rate may not be achievable with undersized or poorly designed overhead receivers.

Quality

Injection location

Injection rate

Comment

Page 42 of 58


Target or Limit


Measurement and control

Accurate measurement and control of wash water flow is essential especially in locations where on water feed is used to supply different parts of the system, such as the overhead and the fin fans.

Nozzle design

Spraying Systems Company, Wheaton, Illinois, (www.spray.com) “Whirljet-CX” design, standard hollow cone nozzle has been used in some Aramco refineries.

Nozzle orientation

Nozzle metallurgy

12.5

Co-current with the process stream flow.

Orient spray nozzle to spray downward along center line of vapor line

Hastelloy C-276, Inconel 625

Corrosion resistant alloys such as Hastelloy C-276 or Inconel 625 are the materials of choice for this service but only available in batches of 25 or more from the manufacturer. SS 316L and 316F have been used as a less desirable alternative in crude unit overhead systems. Rabigh Refinery uses alloy 600.

Chloride Injection There are differences in operation between semi-regenerative and continuous catalytic reformers. The differences are related to the amount of chloride injected, to replace chloride lost from the catalyst during the run and maintain catalyst activity, and whether the chloride is injected continuously. Old reformer units use fixed bed reactors in series. Typically, four reactor beds are used in a cascade arrangement. These units are referred to as semiregenerative catalytic reformers. Removing one bed at a time from service and physically opening the reactor and removing and replacing the catalyst achieve regeneration of this type of process. Continuous Catalyst Regeneration (CCR) platforming is another catalytic reforming process which is operated fairly dry to minimize stripping chlorides from the catalyst and forming hydrochloric acid that is very corrosive. In CCR, the catalyst is continuously withdrawn from the reactor then regenerated, activated and fed back to the stacked reactor bed. The chloride content of the catalyst must be kept in the range that is provided by the catalyst supplier to maintain good catalyst activity and selectivity. To maintain chloride on the catalyst at an optimum level as per catalyst supplier recommendations (determined by catalyst sampling), and a moisture level in the recycle gas (determined by on line recycle gas moisture analyzers), it is necessary to continuously inject a solution of chloride, methanol, and reformate as a dilution agent. The injection rate of each chemical required is expressed as ppm wt% of material active ingredient based on the unit feed rate.

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12.5.1


Design Basis The injection quill and as much of the related piping and valves as possible have often been fabricated from Inconel 600 (UNS N06600), which has sufficient nickel content to make it immune to chloride stress corrosion cracking.

12.5.2

Injection locations ●

Fixed Bed Naphtha Reforming Units (Semi-Regenerative Catalytic Reformers) In Semi-Regenerative Catalytic Reformers, solution of chloride is injected continuously ahead of the reactors to replace chloride lost from the catalyst during the run and maintain catalyst activity. Sometimes methanol is added to maintain minimum water in the recycle gas. Catalyst life is improved if a small amount of water is present but not enough water to wash chlorides off the catalyst.

●

Continuous Catalyst Regeneration (CCR) Platformer In the CCR Platformer, solution of chloride is injected in the platformer feed line. Chloride is also injected to CCR regenerator in chlorination zone to keep the proper activity of the platformer catalyst base function. The injection of chloride, from the chloride storage tank, serves both platformer startup and CCR normal operation.

12.5.3

Requirements for Chloride Injection System Table-7 summarizes the chloride injection requirements. Refinery must have current as-built quill detailed design drawings which also specify the quill materials of construction. These drawings should be up-to-date and signed-off.

Page 44 of 58



Table 7 - Chloride Injection Requirements Variable /Location

Injection location

Nozzle insertion

Nozzle metallurgy

12.6

Target or Limit

Comment

Ahead of the reactors in semiregenerative catalytic reformers

The chloride is continuously injected

In the platformer feed line of the first heater

The chloride is continuously injected

Downstream from the heaters

The chloride is continuously injected to avoid any possible buildup of chloride in the heater tubes

In the chlorination zone of CCR regeneration tower

The chloride is continuously injected to keep the proper activity of the platformer catalyst base function

Between the CCR Combined Feed Exchangers

The chloride is intermittently injected during start-up.

Inject centerline of the pipe

The injection nozzle for chloride solution should be extended to the centerline of the pipe to assure proper mixing and to protect against localized corrosion.

Alloy 600 (Inconel 600)

Stainless Steel 316L shall not be used for this service since this alloy has been very susceptible to chloride stress corrosion cracking. Alloy 600 (Inconel 600) has sufficient nickel content to make it immune to chloride stress corrosion cracking.

Antifoulant Injection Fouling deposits can degrade the operation of refinery process units in several ways: restricting fluid flow, reducing heat transfer rates, shortening service life, and compromising product quality. While fouling can be found throughout the refinery, the most common problem area includes Condensate Fractionation Unit. Fouling deposits can consist of inorganic materials, such as iron sulfide corrosion by-products, and organic materials, such as agglomerated asphaltenes, thermally degraded polymer, and coke. Deposits often contain a complex mixture of organic and inorganic materials. An antifoulant is a chemical additive which may be injected into a process stream at low concentration to prevent the buildup of deposits on downstream tube/shell exchangers. Because of the variety of complex mechanisms which contribute to an overall fouling problem, no single balanced formulation is effective for all fouling cases. Consequently, each fouling problem is highly individual and dependent on many variables such as experience on similar operating units, unit history, stream characterization, deposit analysis, and/or laboratory screening. The use of antifoulants is often a matter of experimentation to establish which compound is most effective. Then, the success of an antifoulant application depends largely upon properly selecting the Page 45 of 58



right antifoulant for the fouling problem at hand and determining what dosage level is required to maintain fouling control. 12.6.1

Design Basis The injection quill should be made out of 316L stainless pipe.

12.6.2

Injection Locations Common applications of antifoulants have included preheat exchangers and furnaces in desalted crude, atmospheric bottoms, coker feed, or hydroprocessing unit services. Treatment of FCCU slurry circuits, fuel gas lines, pyrolysis gasoline, coker and FCCU light ends, and lube extraction solvents has sometimes been performed depending on plant operations.

12.6.3

Requirements for Antifoulant Injection System The detailed design of the antifoulant injection system is shown in the Library Drawing # DB-950175. Table-8 summarizes the antifoulant injection requirements. Refinery must have current as-built quill detailed design drawings which also specify the quill materials of construction. These drawings should be up-to-date and signed-off. Table 8 - Antifoulants Injection Requirements

Variable /Location

Target or Limit Initial feed rate should be determined by experience with similar situations or laboratory testing.

Injection rate

Injection location

Fouling measurement and control

Ongoing feed rates and performance verification should be determined by monitoring heat transfer coefficients or fouling factors across critical heat transfer equipment. Preheat exchangers and furnaces in desalted crude, atmospheric bottoms, coker feed, hydroprocessing unit services.

Comment

For example: 10 ppm of Nalco Thermogain EC3019A chemical (Heavy aromatic Naphtha, Naphthalene) was found to be optimum injection rate for Condensate Fractionation Unit.

For example: downstream of condensate preflash drum at condensate fractionation unit at Ras Tanura Refinery. Overall heat transfer coefficient and pressure drop can be used as values in quantitative evaluation of heat exchanger fouling.

Page 46 of 58



Target or Limit

Comment

Retractable


12 o’clock

Normal orientation.





Quill orientation

Co-current with the process stream flow

The quill shall be installed in the pipe so that the hole of the quill faces the fluid downstream.

Quill metallurgy

the injection nozzle should be made out of 316L stainless pipe

Quill design

13

Upstream Facilities and Gas Plants Chemical Injection Management of corrosion, scale formation, oxygen content and microbial populations, are essential in oil and gas production and processing systems. In addition, demulsifier chemical is used in the GOSPs to assist in water-oil emulsion breaking/separation. The injection of the inhibitor is a standard practice to control internal corrosion and scale build-up in carbon steel equipment and piping. This strategy has been shown to be very successful and cost effective. 13.1

Design Basis Standard two-inch high pressure access fittings and injection quills are commonly used in GOSPs, oil & gas processing facility and gas plants for injecting typical oilfield treatment chemicals. High pressure access fittings are designed to permit safe, relatively easy insertion and retrieval of injection quills as well as other devices (such as coupons or monitoring equipment) while under full operating pressure. This type of injection quill can be removed for cleaning while system is under pressure. The injection components, other than the access fitting body, shall be made out of 316L stainless steel or better and shall be suitable for sour service and meet the requirement of SAES-A-301, if injection is required into a sour service process. Access fittings for injection must be installed in straight run pipe. The fitting must not be installed closer than a minimum of two pipe diameters downstream of a bend, valve or reducer and there must be a minimum run of 5D of straight Page 47 of 58



pipe downstream of the fitting before a bend, reducer, etc. When more than one access fitting is installed in one location, the fittings must be separated by a minimum three (3) feet. In order to operate the retriever, a minimum of twelve (12) inches clearance is required around the access fitting body and a minimum of eight (8) feet is required above or to the side of the pipe for top and side mounted fittings, respectively. Check valves are required immediately upstream of the shut-off valve at the fitting. The shut-off valve should be 316L stainless steel and after installation onto the nipple must be seal welded in accordance to Saudi Aramco welding procedures. Positive shut-off valve required such as gate, needle or ball. Short nipples and shutoff valves must be rated for sour service and they should be identifiable (grade and rating) as per SAES-L-105, Section 5. All valves installation and seal welding should be as per SAES-L-110, Section 8. If a chemical injection fitting is not in service, the solid plug, injection nut and quill shall be extracted, the quill must be removed from the injection nut and a solid stainless steel pipe plug installed in its place. This prevents service fluid from migrating up the quill through the hollow injection nut and contacting and possible corroding the threaded nipple installed in the access fitting body tee. Prior to re-installing the plugged injection assembly into the access fitting the upper and lower O rings shall be replaced. 13.2

Injection Locations The following is a list of some of the chemical types and their typical injection locations in upstream facilities and Gas Plants: ♦ Corrosion Inhibitor • • • • • • • • • •

GOSP production/test header Trunk lines/flow lines with high water cut GOSP Wasia wash water line GOSP LPPT/IPPT/HPPT gas compressor discharge lines GOSP dry gas line to NGL GOSP disposal water header GOSP wash water supply GOSP fire water supply Disposal water line in the 3-Phase Separators (Plant 429 of Abqaiq Plants) Gas out line from De-Ethanizer to Gas Plant (Plant R-57 of Abqaiq Plants) Page 48 of 58


• • • • • • • • • • • •


Suction line of the inter-stage/after coolers in NGL Plant (All NGL Plants in Abqaiq Plants) Off-gas from the De-Ethanizer reflux drum to Gas Plant (Plant 462 of Abqaiq Plants) Off-gas from the De-Ethanizer surge drum to condenser (Plant 462 of Abqaiq Plants) Off-gas from stripper feed drum to De-Ethanizer or Gas Plant (Plant 462 of Abqaiq Plants) NGL line (QA-10) to Ras Tanurah Refinery (Plant 462 of Abqaiq Plants) Total off-gas line to De-Ethanizer feed chiller (Plant 462 of Abqaiq Plants) Suction line of stripper overhead cooler (Plant 499 of Abqaiq Plants) Overhead gas line (Plant 334 of Abqaiq Plants) Discharge of condensate shipper pump (Gas Plants) Downstream of the gas wellhead christmas tree (Gas Plants) Ethane “C2” injection well (only during the reproduction in some of the Gas Plants) Sour/Sweet wet gas flowlines

♦ Scale Inhibitor • • • • •

GOSP production/test header GOSP disposal water header IPPT/HPPT crude oil out stream in some GOSPs Disposal water line in the 3-Phase Separators (Plant 429 of Abqaiq Plants) Discharge of Condensate Shipper Pump (Gas Plants)

♦ Oxygen Scavenger •

Disposal water line in the 3-Phase Separators (Plant 429 of Abqaiq Plants)

♦ Biocide Injection •

Disposal water line in the 3-Phase Separators (Plant 429 of Abqaiq Plants)

♦ Demulsifier Injection •

Production Manifold

Page 49 of 58


• • • 13.3


GOSP test header Dehydrator/Desalter inlet Upstream of 3-Phase Separators (Plant 429 of Abqaiq Plants)

Requirements for Chemical Injection System in Upstream Facilities and Gas Plants The typical design of the chemical injection point is shown in the library drawing DA-950035 “2-Inch high Pressure Access System Chemical Injection and Corrosion Monitoring”. The following table summarizes the chemical injection requirements in upstream facilities and Gas Plants. Table 9 - Chemical Injection Requirements

Variable/Location

Target or Limit

Injection rate

Comments As communicated by the Area Corrosion Engineer

install in straight run pipe The fitting must not be installed closer than a minimum of two pipe diameters downstream of a bend, valve or reducer

Access fitting design

there must be a minimum run of 5D of straight pipe downstream of the fitting before a bend, reducer, etc. the fittings must be separated by a minimum three (3) feet

This is required when more than one access fitting is installed in one location

A minimum of twelve (12) inches radial clearance is required around the access fitting body and a minimum of eight (8) feet is required above or to the side of the pipe for top and side mounted fittings, respectively.

This is required in order to operate the retriever

The style of the injection quill should have a scarf cut instead of a plain open end

Quill design


The recommended injection location is the center of the pipe to ensure even distribution away from pipe walls and for more homogeneous mix to take place in the pipe.

12 o’clock position Injection quill length


Page 50 of 58



Target or Limit

Comments

Quill orientation

For liquid-phase stream, the quill should be installed in the pipe so that the angled face of the quill faces the fluid downstream. While for mixed and vapor phase stream, the angled face of the quill should face the fluid upstream as shown in Figure 6 & 7.

To insure proper positioning of the quill cut in the pipe, the solid plug should be permanently marked to show orientation. One of the recommended field practices is to permanently mark the long side of the quill with a straight line using a file, small hacksaw cut or waterproof paint marker.

Quill metallurgy

The injection quill should be made out of 316L stainless material. Pipe and not tubing shall be used to fabricate the quill.

The quill material should be suitable for sour service and meet the requirement of SAES-A-301, if injection is required into a sour service process.

14

Steam Generator Chemical Injection Chemical treatment of water inside the steam generators is necessary to prevent scaling and corrosion in the steam generator and its associated condensate system. Scaling in steam generators is caused by impurities being precipitated out of the water directly on heat transfer surfaces or by suspended matter in water settling out on the metal and becoming hard and adherent. Scaling in steam generators will result in excessive fuel consumption due to loss of heat transfer and may also cause localized overheating. This can lead to tube failure. The first preventative measure for scaling is to supply good quality water as make–up feed water. Feed water also contains dissolved gases such as oxygen or carbon dioxide. These gases in the presence of water and metal can cause corrosion. Oxygen attack is one of the most common causes of corrosion inside steam generators. Oxygen attack can cause damage to economizers, steam drums, mud drums, boiler headers and condensate piping. A deaerator removes most of the oxygen in feed water; however, trace amounts are still present and can cause corrosion-related problems. Oxygen scavengers are added to the feed water, preferably in the deaerator storage section, to react with the trace amounts of oxygen not removed by the deaerator. Corrosion can also occur from excessive alkalinity of excessive pH of the boiler water. This caustic attack is most likely to occur under scale or deposits, where very high local concentrations of hydroxide can build or in zones where insufficient cooling. Neutralizing Amines are high pH chemicals that intended to react with trace levels of carbon dioxide in the condensate system. Being alkaline, neutralizing amines also raise the pH in the condensate system, which aids in reducing corrosion rates.

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14.1


Design Basis Refer to section 13.1 and table 9 for complete design requirements of the steam generator chemical injection point. Chemicals used in steam generator systems are best injected neat, to avoid batch preparation errors and to minimize the size of the dosing pumps. Most water treatment vendors supply chemicals in semibulk tanks of 1000 liter capacity. The use of semi-bulk tanks avoids the need for day tanks. For more information on boiler water treatment refer to COE-202.02 in the engineering encyclopedia under corrosion/industrial water treatment. There will be separate best practices for utility cooling towers and desalination units.

14.2

Injection Locations The optimum injection locations are indicated in Figure 11.

Figure 11 - Optimum Injection Points for Steam Generator Chemicals

15

Chemical Dosage Control Chemical injection system requires continual operator attention to make sure that the correct dosage rate is being injected in the system. Adjustments to the volume of chemical injected should be made to maintain the dosage rate set point. The operator should visually check the condition of the chemical pumps, tanks and piping in a daily basis. Maintaining the optimum chemical dosage to process streams and monitoring the effect on corrosion rates are extremely important in corrosion control. Failure to do so

Page 52 of 58



would result in surprises and unplanned equipment failures. Plant operators should check the chemical injection rates twice per shift. Frequent field visits and spot-checks should be conducted by the Area Corrosion Engineer to ensure strict adherence to the chemical injection procedures. The intent of the spot checks is to bring to the attention of the operations organizations the deficiencies in the chemical dosage rates, chemical injection pumps, type of chemicals used and similar issues. Monthly status reports should be issued by the area Corrosion Engineer and sent to the Operations Foreman, highlighting the monthly spot check deficiencies noted and the required course of action. Tracking of chemical consumption and adherence to established injection targets is an Operations responsibility. Operations staff should highlight the deficiencies up through their organization on a daily basis. Follow-up visits by the Corrosion Engineer should be made to observe the implementation of recommendations. In addition to the periodic reports, more formal chemical injection system review meetings and audits are recommended to be conducted regularly. The frequency of review meetings and audits depends on the corrosivity and history of the plant piping and equipment system, and has to be determined for each specific case and chemical. The success of the effective chemical injection program ultimately revolves around the ability of operations personnel, process and corrosion engineers to interact and effectively communicating targets, objectives, and problems. Strict adherence to this procedure allows the plant operations staff to reliably and accurately optimize the chemical injection rate. This level of chemical dosage control can significantly reduce the need for maintenance, lower the risk of unexpected failure and further reduce operation and maintenance costs by assuring adequate dosage of the chemical is injected in the plant piping and equipment. 16

Chemical Injection Effectiveness The most important aspect of the chemical obviously is its performance and effectiveness. Therefore, regular corrosion monitoring to obtain trended data are the only means to ensure that chemical injection is effective. Inspection is also used periodically to ensure the integrity of plant piping and equipment. The monitoring and recording of all available parameters, including flow rates, and chemical consumption, is required to ensure that the chemical treatment program is operated and managed correctly. Corrosion monitoring is used to confirm that inhibition is actually controlling the corrosion to an acceptable rate. Monitoring can: •

Detect of compliance conditions

Page 53 of 58


•


Provide plant operators with sufficient reaction time to implement remedial actions such as:

Repair of injection equipment Change of operating procedures Change of chemical dosage rate

The following data should be collected to assist in system performance evaluation: •

Corrosion monitoring data such as:

Iron counts (regular chemical analysis to provide trends) Corrosion coupons On-line monitoring probes

•

Chemical injection data

•

Inhibitor residuals

•

Process Parameters (in-direct measure of corrosion) such as:

Flow rate Fluid chemistry Water cut Temperature Pressure pH Gas composition

•

System upsets

•

Chemical cost

•

Maintenance record

•

Inspection data including but not limited to:

Periodic ultrasonic surveys RT MPI LPI Instrument scraping runs for pipelines

Reliance on data from a single corrosion monitoring method is not recommended. The aim should be to use data from at least two types of technique to obtain consistent information; for example, on-line corrosion monitoring, weight loss coupons, and iron Page 54 of 58



counts. Appropriate sampling equipment location is also crucial for the determination of the system corosivity. Data from the monitoring activities outlined above should be gathered together and correlated with relevant process data and other information. The trended data should enable out-of-compliance conditions to be detected and for the appropriate corrective actions to be taken or for repairs to be completed before the operation or integrity is compromised. The main goal of overall process system condition monitoring, should be to detect out of compliance conditions very early after their occurrence and to correct the condition and return the system to compliance before there would be enough damage to the system to warrant repair. 17

Strategies for Chemical Optimization Regular monitoring and adjustments are typically needed to optimize the performance of the costly chemicals due to operational conditions changes. The chemical optimization activity concentrates on injecting the correct amount of treatment chemical into a system or specific piece of equipment under the current process conditions, to achieve the result anticipated from the application of the chemical. The chemical requirement is driven by factors such as water cut, water volume, flow regime, and condition of the equipment. However, the ultimate measure of whether or not enough chemical is used can only be determined by consideration of other factors such as corrosion monitoring data and/or the amount of active corrosion detected by the OSI program, results of inspections during T&Is and process variables changes. The correlation between the inspection data and the corrosion monitoring data allows the corrosion monitoring data to be interpreted with better confidence to manage the chemical injection program in an efficient manner. Information from corrosion monitoring and inspection activities should be collated and gathered together to help in the chemical optimization. This information should also include relevant process conditions and chemical inhibition data. Typically the data gathered should include: •

Process conditions, highlighting any changes.

•

Visual observations.

•

Corrosion monitoring data.

•

Weight loss coupons. Electrical Resistance (ER) probes. Linear polarization resistance (LPR) probes

Inspection data covering

Ultrasonic inspection data (OSI data) Page 55 of 58


•


Radiographic (X-ray) inspection data T&Is inspection reports Leak History Instrument scraping results for pipelines

Corrosion and failure analysis reports

Not all inspection and monitoring systems are required/applicable for any particular facility and their use will be dependent on the type of corrosion process/material damage that is anticipated. It is not intended that this Best Practice document provides a detailed description of the different techniques which can be found elsewhere. The usual monitoring tools for chemical optimization are corrosion coupons, Linear Polarization Resistance (LPR), electrical resistance (ER) probes and iron counts. Weight loss coupons provide a check on LPR and ER results and identify the onset of pitting but do not usually give specific information about weld corrosion. The probes are often installed on a side or top stream of the main production line, for measuring corrosion rates. LPR measurement can provide a relatively faster response than ER probes where both of them are used to detect general corrosion. The main difficulty with this approach is that flow and corrosive conditions in the side or top stream can be different from those in the main lines. This is particularly true in the case of localized corrosion. The localized corrosion can be as crevice or pitting caused by water accumulation at the bottom of the line. In addition, the duration of the chemical injection optimization study is often not long enough to ensure that stable corrosion conditions have been established. Chemical optimization requires faster methods so on-line corrosion monitoring should be utilized to aid the plant engineers and operators in optimizing the corrosion inhibitor required. On-line corrosion monitoring will allow the operators to vary the injection rates of chemicals as flow conditions fluctuate. The corrosion rate can be monitored hourly as the chemical inhibition levels varied and a maximum allowable corrosion rate can be set and acted upon by the operators. Moreover, On-line corrosion monitoring permits the operators to have a closer look at the corrosion characteristics of the plant piping, and to determine the extent of temporary corrosion protection afforded by the residual corrosion inhibitor after the chemical inhibition pumps are switched off. Lab analysis for the process should be taken periodically to lead for good monitoring and chemical optimization as well as protection the system. Chemical optimization study should be run over an extended period of weeks/months. The optimization study results should be promptly evaluated. This should be a joint activity with the lead taken by the Corrosion Engineer assisted by the Process Engineer, inspection personnel and vendor's experts.

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Records of injection dosage compared to site deliveries, storage and purchase information can often reveal discrepancies and identify causes of poor performance. 18

Quality Control of Chemicals Chemical injection inhibitors are typically not pure chemicals. Many of the ingredients that are used for the formulation of these chemicals are side stream products having some degree of variation from batch to batch. These chemicals undergo a multitude of laboratory and field tests before they can be injected in the operating units. SAES-A-205 “Oilfield Chemicals” and SAES-A-208 “Water Treatment Chemicals” establish requirements for selection, quality assurance, quality control, and first-fill purchase of oilfield and water treatment chemicals. The purpose of these standards is to implement a program that results in the cost-effective purchase and performance of oilfield and water treatment chemicals.

19

Contributing Authors Name

Department

Ahmed M. Al-Zahrani

Consulting Services Department

Ahmad S. Al-Omari


The authors of this document would like to thank all of those who contributed to produce this Best Practice and special thanks go to: Name

Department

Robin D. Tems


Brian W. Burgess

N. A. Producing Engineering Department

Graham R. Lobley


1 July 2007

Revision Summary New Saudi Aramco Best Practice.

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Appendix A INSPECTION UNIT Chemical Injection Point Datasheet (Injection Point Number: Title) 1. Receiving Stream Description Unit Description Line Number Receiving Stream Phase Line Metallurgy

G

L

P & ID No. Line Size (inch)/Schedule Operating Temperature (°F)

G/L

Operating Pressure (psi)

Corrosion Rate (mpy)

Upstream Equipment

Downstream Equipment

Flow Rate (BPD or MMSCF/D)

Normal:______________ Min:________________ Max: ____________ Optimum:___________

2. Injection Stream Description Injection Phase Line Metallurgy

G

L

Line Size (inch)/Schedule Operating Temperature (°F)

G/L

Operating Pressure (psi) Injection Rate (GPD) Type of Injection Back Flow Prevention

Corrosion Rate (mpy) Normal:______________ Min:________________ Max: ____________ Optimum:___________ Continuous

Intermittent (Frequency:_____________________ )

Check valve

Other (Specify:____________________________ )

3. Injection Hardware 45o Bevel Quill

Injection Point Type Injection Origin (From) Direction of Injection Injection Tube Metallurgy Flow Measurement System

Top

Spray Nozzle Bottom

Normal elbow

Side of Horizontal Pipe

Injection Face the Fluid Upstream

Small Circular Hole Side of Vertical Pipe

Injection Face the Fluid Downstream

Flow Control System

Name of Vender (if any) Nearest Pipe Change is Distance

Bend

Tee

Reducer

Orifice

Other (Specify:_______________ )

4. Chemical Data Generic Description Injection Purpose Supplier Product Name Injection Start Date (m/d//yr)

5. Injection Point Inspection Isometric Sketch No. Inspection Interval Inspection Technique Last Inspection Date Next Inspection Date

6. Note: Attach any available information/sketch/P&ID related to this injection point.

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SABP-A-015

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