NACE SP0192-2012 Monitoring Corrosion in Oil and Gas Production with Iron Counts (Item No 21053).pdf

1、 Standard Practice Monitoring Corrosion in Oil and Gas Production with Iron Counts This NACE International standard represents a consensus of those individual members who have reviewed this document, its scope, and provisions. Its acceptance does not in any respect preclude anyone, whether he or she

2、 has adopted the standard or not, from manufacturing, marketing, purchasing, or using products, processes, or procedures not in conformance with this standard. Nothing contained in this NACE International standard is to be construed as granting any right, by implication or otherwise, to manufacture,

3、 sell, or use in connection with any method, apparatus, or product covered by Letters Patent, or as indemnifying or protecting anyone against liability for infringement of Letters Patent. This standard represents minimum requirements and should in no way be interpreted as a restriction on the use of

4、 better procedures or materials. Neither is this standard intended to apply in all cases relating to the subject. Unpredictable circumstances may negate the usefulness of this standard in specific instances. NACE International assumes no responsibility for the interpretation or use of this standard

5、by other parties and accepts responsibility for only those official NACE International interpretations issued by NACE International in accordance with its governing procedures and policies which preclude the issuance of interpretations by individual volunteers. Users of this NACE International stand

6、ard are responsible for reviewing appropriate health, safety, environmental, and regulatory documents and for determining their applicability in relation to this standard prior to its use. This NACE International standard may not necessarily address all potential health and safety problems or enviro

7、nmental hazards associated with the use of materials, equipment, and/or operations detailed or referred to within this standard. Users of this NACE International standard are also responsible for establishing appropriate health, safety, and environmental protection practices, in consultation with ap

8、propriate regulatory authorities if necessary, to achieve compliance with any existing applicable regulatory requirements prior to the use of this standard. CAUTIONARY NOTICE: NACE International standards are subject to periodic review, and may be revised or withdrawn at any time in accordance with

9、NACE technical committee procedures. NACE International requires that action be taken to reaffirm, revise, or withdraw this standard no later than five years from the date of initial publication and subsequently from the date of each reaffirmation or revision. The user is cautioned to obtain the lat

10、est edition. Purchasers of NACE International standards may receive current information on all standards and other NACE International publications by contacting the NACE International FirstService Department, 1440 South Creek Dr., Houston, Texas 77084-4906 (telephone +1 281-228-6200). Revised 2012-0

11、3-10 Revised 1998 Approved 1992 NACE International 1440 South Creek Drive Houston, Texas 77084-4906 +1 281-228-6200 ISBN 1-57590-073-4 2012, NACE International NACE SP0192-2012 (formerly RP0192) Item No. 21053 SP0192-2012 NACE International i _ Foreword This standard practice describes the use of ir

12、on counts as a corrosion-monitoring method and some common problems encountered when using this method. For several years, NACE Task Group (TG) T-1C-7, “Iron Determination,” examined the problems and successes experienced by oil-producing companies and service companies using iron counts as a corros

13、ion-monitoring method and determined that iron counts on wellhead samples may provide information on the existence of downhole corrosion and the effectiveness of inhibitor treatments. Iron counts may also give information on the corrosion activity in flowlines in waterflood systems and oil-productio

14、n operations. This standard is a guide for those designing corrosion-monitoring programs as well as those carrying out the programs in the field. This standard was originally prepared in 1992 by TG T-1C-7, a component of Unit Committee T-1C, “Detection of Corrosion in Oilfield Equipment.” T-1C was c

15、ombined with Unit Committee T-1D, “Corrosion Monitoring and Control of Corrosion Environments in Petroleum Production Operations.” This standard was revised by TG T-1D-55 in 1998, and in 2012 by TG 373, “Monitoring Corrosion in Oil and Gas Production with Iron Counts.” This standard is issued by NAC

16、E International under the auspices of Specific Technology Group (STG) 31, “Oil and Gas ProductionCorrosion and Scale Inhibition.” In NACE standards, the terms shall, must, should, and may are used in accordance with the definitions of these terms in the NACE Publications Style Manual. The terms shal

17、l and must are used to state a requirement, and are considered mandatory. The term should is used to state something good and is recommended, but is not considered mandatory. The term may is used to state something considered optional. _ SP0192-2012 ii NACE International _ NACE International Standar

18、d Practice Monitoring Corrosion in Oil and Gas Production with Iron Counts Contents 1. General . 1 2. Sampling . 1 3. Analysis . 4 4. Interpretation . 4 References 8 FIGURES Figure 1: Typical Double-ended sample receiver and connection on the bottom of a flowline. 3 Figure 2: Nomograph showing amoun

19、t of iron lost per day in a water distribution system. Iron-loss values are found by relating measured values of iron concentration in the water to flow rate through the system. (Reprinted from NACE Publication TPC 5). . 6 Figure 3: Graphical presentation of iron production rate vs. time plus pertin

20、ent operating information. 8 Appendix A: Safety Considerations When Handling H2S . 9 _ SP0192-2012 NACE International 1 _ Section 1: General 1.1 The anomalies experienced when using iron counts as a corrosion-monitoring method result mostly from the varying, usually uncontrollable, conditions found

21、in almost every production system. Because the term iron count refers to the concentration of iron dissolved in the water expressed as milligrams per liter (mg/L), milligrams per kilogram (mg/kg), or parts per million by weight (ppmw), those monitoring corrosion using iron counts must specify whethe

22、r the iron content is based on the total fluid produced and whether the iron is reported as soluble iron, ferrous iron, or total iron. The usual oilfield iron count is total iron content of an acid-treated sample. When iron counts are used to monitor corrosion trends, the same species must be determ

23、ined consistently for a given sampling point in a system. For comparison of systems producing varying amounts of water, a more meaningful tool is the iron production rate that takes into consideration the water flow rate at the time of sampling. The iron count is converted to an iron production rate

24、, usually expressed in kilograms of iron per day (kg/d) or pounds of iron per day (lb/d). 1.1.1 The analyst should evaluate available test methods for iron content to determine the most suitable method regarding detection limits, accuracy, precision, and interferences. Specific analytical procedures

25、 are not addressed in this standard. The exact method of sampling and sample treatment required to separate and analyze for ferrous, ferric, soluble, and total iron content of a water sample are adequately covered in the analytical procedures described by Rydell and Rodewald,1 Eaton et al.,2 and AST

26、M(1) D1068.3 If techniques are used to analyze for the individual species of iron, the final report must indicate the form of iron being reported. If only the typical total acid-soluble iron content is determined, the final report should indicate that the result is “total iron.” 1.1.2 For the purpos

27、es of this standard, it is presumed that iron counts are performed on aqueous samples. Analysis of hydrocarbon samples for iron content is possible and the technique is practiced by some corrosion engineers. One suggested technique for “iron in oil” is described by Rydell and Rodewald.1 1.2 The mech

28、anical arrangement, physical conditions, and chemical environment in almost every system or part of a system must be evaluated under comparable conditions before the iron content of each sample can be correctly interpreted. The iron counts measured are not of any value if these variables are not con

29、sidered in the interpretation. 1.3 Monitoring corrosion by the use of iron counts may be done easily, inexpensively, and quickly in the field. Iron production rates, unlike test specimen corrosion rates, may give some indication of corrosion upstream or downhole from the sampling point. Iron counts

30、are useful when surface-monitoring devices, such as test specimens, may not reflect downhole conditions, such as when paraffin forms on test specimens and when downhole conditions are greatly different from surface conditions. The principal reason for the historical popularity of iron counts as a st

31、andalone corrosion-monitoring method is that in many small production facilities other forms of corrosion-monitoring facilities have not been installed. However, iron count measurements should be combined with other corrosion-monitoring methods whenever possible. 1.4 Generally, iron counts from flui

32、ds containing dissolved sulfides or dissolved oxygen are not reliable because of precipitation of iron sulfide or iron oxide solids that may deposit on metal surfaces as well as remain suspended in solution. Although the iron counts may vary over time as temperature, hydrogen sulfide (H2S), or oxyge

33、n levels vary, the iron count value actually represents the solubility of iron and not the severity of corrosion upstream from the sampling point. Therefore, the use of iron counts as a corrosion-monitoring method must be validated for each specific use. 1.5 Proper safety precautions when dealing wi

34、th sour systems are addressed in API(2) RP 54.4 Appendix A (nonmandatory) covers safety considerations when handling H2S, and information on the toxicity of this gas. _ Section 2: Sampling 2.1 Iron counts are used for monitoring the iron content of the water phase at different points in a flowing sy

35、stem, thereby indirectly indicating the effectiveness of corrosion control. The results are useful if they are representative of the iron content of the flowing fluid. Solids, including old or fresh corrosion products in the form of iron compounds, may accumulate in a sampling point or trap under st

36、atic conditions. Corrosion of the sample point may also contribute to the iron count. (1) ASTM International (ASTM), 100 Barr Harbor Dr., West Conshohocken, PA 19428-2959. (2) American Petroleum Institute (API), 1220 L St. NW, Washington, DC 20005-4070. SP0192-2012 2 NACE International 2.1.1 The sam

37、ple point in an oilfield system usually consists of a tee or nipple and valve welded onto a pipeline or vessel. The fitting may not be used exclusively for sampling; rather, many access fittings are originally installed to monitor pressure or other parameters in the system. In horizontal lines carry

38、ing water and hydrocarbon in stratified layers, the ideal location for sample collection is on the bottom of the line. If the flow in a system is annular, a representative sample may be obtained from a sample point at any position along the flowing stream. A representative sample of the aqueous phas

39、e shall be obtained, even if this requires the use of special sample access fittings. To obtain a representative sample of the flowing water, the sample fitting shall be blown down to remove any accumulated solids and stagnant water before obtaining a sample for analysis. The following sampling proc

40、edure shall be used to obtain samples that are representative of the flowing stream. 2.1.2 After the sample fitting is purged to a suitable waste container, conditions are correct for obtaining a reasonably representative sample of fluid for iron analysis. 2.1.2.1 If a steady flow of liquids exists

41、in the system because of turbulent flow or a relatively high volume of liquids passing through the system, a sample shall be drawn directly into a suitable sample container made of corrosion-resistant or iron-free materials. The container may be a glass or plastic bottle if the system pressure permi

42、ts safe collection of the sample. After purging the sample line, and while obtaining the desired sample, the valve on the sample line shall not be adjusted to either increase or decrease the flow. Any physical adjustments that disrupt the flow rate may dislodge iron precipitates from the sample poin

43、t and cause them to enter the sample container. 2.1.2.2 If the flow in a low-pressure system is very slow or if small quantities of free water are present, a sample shall be collected over an extended period of time as described in Paragraph 2.1.3. The approximate time required to collect a sample m

44、ay be easily determined by observing the presence or absence of free water in a quickly obtained sample collected from a system in a glass or plastic container. The sampling time period must be extended if sufficient aqueous fluid for analysis is not readily obtained. A corrosion-resistant sample re

45、ceiver with a pressure rating consistent with the maximum system pressure should be installed at the six oclock position of the line (see Figure 1). Caution should be used to avoid galvanic attack between the sample receiver and the system by use of an insulating flange between dissimilar materials

46、of construction. The container should be suitably cleaned and free of any foreign matter. The sample fitting must have been purged as described in Paragraph 2.1.1 prior to installation of the sample receiver. The bottom valve must remain closed and both the valve on the sample fitting and the top of

47、 the sample receiver must remain open during the sample collection period. 2.1.4 Sufficient time must be allowed for water to collect in the sample receiver. In some systems this may be accomplished in a few minutes, although it may require 12 to 24 hours in gas well flowlines when intermittent slug

48、s of water are produced. 2.1.5 The sample receiver shall be isolated from the system by closing both the fitting and top receiver valves. The sample receiver shall be removed from the line. Care should be taken to bleed pressure slowly when the sample receiver is moved from the sample access fitting. If the system is sour and the receiver fittings contact H2S gas, see Paragraph 1.5 for appropriate safety precautions and considerations when handling H2S. 2.1.5.1 A sample of the colle