Identifying Key Performance Indicators in Oilfield

Paper No.

4348

Identifying Key Performance Indicators for Corrosion in Oilfield Water Handling Systems Olagoke Olabisi, PhD Director, Internal Corrosion Engineering Corrpro Companies, Inc., Houston, Texas [email protected]

Amer Jarragh Snr Corr Eng, Inspection & Corrosion Team Kuwait Oil Company, Ahmadi, Kuwait

Yousef Khuraibut Corr Engineer, Inspection & Corrosion Team Kuwait Oil Company, Ahmadi, Kuwait

Ashok Mathew Corrosion Chemist, KOC ICMS Contract Corrpro Companies, Inc., Ahmadi, Kuwait

ABSTRACT Key performance indicators are used to track the efficiency of the prevailing corrosion risk management strategy, namely, the integration of corrosion, process monitoring, inspection, mitigation, environmental control, and materials management. In an earlier paper1, a methodology was outlined for the use of a single key performance indicator, namely, the corrosion rate, in tracking monitoring strategy, mitigation strategy, and pipeline integrity. This paper seeks to identify other key performance indicators. At Kuwait Oil Company (KOC), internal corrosion monitoring activities are carried out in 22 gathering centers, early production facilities, 5 booster stations (operating), 3 effluent water disposal plants, seawater treatment plant, seawater injection plant, and pipeline network carrying different products. Corrosion and corrosivity trends are monitored using weight-loss coupons, electronic probes, bioprobes, hydrogen patch probes, galvanic probes as well as the measurement of iron content (total and dissolved) and manganese content. Corrosivity trend is also monitored using pH, conductivity, total dissolved solids, total hardness, dissolved oxygen, H2S concentrations, CO2 concentrations, bacterial population density and corrosion inhibitor residuals. These activities consume significant resources. The present paper is focused on identifying parameter(s) that could serve as key performance indicator(s) for corrosion and enable the company to operate with greater cost effectiveness, efficiency, reliability and control of the state of corrosion integrity of oilfield water handling systems. Key words:

Key Performance Indicator (KPI), Corrosion Control Metrics, Corrosion trend, Corrosivity Trend, Corrosion Integrity.

©2014 by NACE International. Requests for permission to publish this manuscript in any form, in part or in whole, must be in writing to NACE International, Publications Division, 1440 South Creek Drive, Houston, Texas 77084. The material presented and the views expressed in this paper are solely those of the author(s) and are not necessarily endorsed by the Association.

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INTRODUCTION Kuwait Oil Company (1) is the sole exploration and producing Operator in Kuwait. Kuwait oil reserve ranks 9th in the world and the Operator are projected to be producing about 4.0 million barrels of oil per day by the year 2020. In the last 60 years of operation, the pipeline network has grown to about 4,800 km. Corrpro (1) has been the Contractor for Internal Corrosion Monitoring Services (ICMS) for the Operator since 2006. The ICMS Project conducts internal corrosion monitoring of all existing facilities under the guidance of the Inspection and Corrosion Team. For the Operator pipeline network, the Contractor conducts corrosion monitoring by using: 1. 2. 3. 4. 5. 6.

Online weight-loss coupons for general/pitting corrosion, deposits, and sessile bacteria Online electronic probes for general corrosion, deposits and sessile bacteria Online bio-probes for sessile bacteria and deposits Fluid sampling for planktonic bacteria analyses Fluid sampling for chemical analyses and treatment chemical residual analyses XRD analyses of solid corrosion products from shut-down vessels and suspended solids from pig runs.

This paper relates to the activities of the ICMS contract pertaining specifically to oilfield water handling systems. Generally, internal corrosion monitoring activities are carried out in 22 gathering centers, early production facilities, 5 booster stations (operating), 3 effluent water disposal plants, seawater treatment plant, seawater injection plant, and pipeline network carrying different products. Inspection and monitoring are the two key processes by which the onset of internal corrosion, external corrosion and stress corrosion cracking can be detected. However, internal corrosion monitoring is able to detect corrosion significantly quicker than inspection techniques. This “early detection” of the onset of corrosion enables a quick response to the changing operational environment, and, when appropriate, an increase in the quantity of treatment chemicals applied to the process fluids, thereby enhancing protection. Thus, internal corrosion monitoring helps to minimize the extent of damage to the base materials, and maintain the structural integrity of the production systems. That is, early detection assists risk-criticality assessment, helps ensure reliability of production and enables the avoidance of losses from equipment replacement and operational disruptions. Online corrosion monitoring locations normally include: (a) each water source; (b) all points downstream of storage units such as tanks; (c) downstream of all biocide injection points, (d) plant outlets; (e) the farthest points in a system (e.g. injection wellhead); and (f) selected worst-case locations (e.g. dead legs, etc.). Depending on risk assessment, fluid sampling is conducted routinely at 30-day, 45-day, or 60-day intervals. Weight-loss coupon corrosion monitoring is done typically at 45-day intervals for locations exhibiting high (5 mpy equal to 0.127 mm/y) to severe (>10 mpy equal to >0.254 mm/y) corrosion characteristics; 90-180 day intervals are used for locations with low (1 mpy equal to 0.0254 mm/y) to moderate ( Recycle Water > Effluent Water. The question then arises, is bacteria population the key performance indicator for corrosion in oilfield water handling systems? To answer that question necessitates the investigation of the effects of a variety of fluid parameters on general and pitting corrosion. This paper is an attempt to do that; an attempt at identifying the parameter(s) that could serve as key performance indicator(s) for corrosion in oilfield water handling systems. To this end, corrosion and corrosivity trends are monitored using weight-loss coupons, corrosion probes, bioprobes, hydrogen patch probes, galvanic probes as well as the measurement of iron content (total and dissolved), and manganese content. Corrosivity trend is also monitored using pH, conductivity, total dissolved solids, total hardness, scaling ions (Ca & Mg), dissolved oxygen, H2S concentrations, CO2 concentrations, carbonates, sulfates, sulfides, bacterial population density, oxygen scavenger residuals, corrosion inhibitor residuals and scale inhibitor residuals. CORROSION CONTROL METRICS FOR OILFIELD WATER HANDLING SYSTEMS There are several generally accepted corrosion control matrices1 classified under system measures, corrosion/erosion, fluid sampling/pigging, inspection, mitigation, repair and/or replacements. In this study, however, the emphasis is on corrosion and corrosivity, discovered through internal corrosion monitoring of the fluid parameters discussed in Table 1, entitled: Significance of Fluid Parameters as Corrosion Control Metrics. Each of the corresponding fluid parameters could be authentically considered a corrosion control metric depending on its capacity to adequately reflect the corrosion state of the system. Consider, for example, a system, which has been experiencing increased corrosion over a period of time. If the trend of increasing corrosion rate versus time is relatable to the ©2014 by NACE International. Requests for permission to publish this manuscript in any form, in part or in whole, must be in writing to NACE International, Publications Division, 1440 South Creek Drive, Houston, Texas 77084. The material presented and the views expressed in this paper are solely those of the author(s) and are not necessarily endorsed by the Association.

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corresponding plot of a parameter over that same period of time, it is perhaps probable that the said parameter plays a role in the observed increased corrosion or corrosivity of the fluid. Table 1 Significance of Fluid Parameters as Corrosion Control Metrics S/N

Parameter

1

pH

2

Conductivity

3

Chloride

4

Sulfate

5

Hydrogen Sulphide (H2S)

6

Total Hardness

7

Dissolved Oxygen (DO)

8

Dissolved Iron

9

Total Iron

10

Manganese (Mn)

11

Corrosion Inhibitor (C.I.) Residual

Significance pH of Brackish Water How does the corrosivity ranking compare with the corrosion severity ranking for the same ©2014 by NACE International. Requests for permission to publish this manuscript in any form, in part or in whole, must be in writing to NACE International, Publications Division, 1440 South Creek Drive, Houston, Texas 77084. The material presented and the views expressed in this paper are solely those of the author(s) and are not necessarily endorsed by the Association.

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water handling system under the current production scenarios? According to NACE RP0775-20052 corrosion severity classification is in terms of corrosion rates in mils per year (1 mil = 0.001 in) or mm/y as illustrated in Table 3.

Table 3 Classification of General and Pitting Corrosion Rates General Corrosion

Pitting Corrosion

Low

< 1.0 mpy (< 0.0254 mm/y)

Low

< 5.0 mpy (0.127 mm/y)

Moderate

1.0- 4.9 mpy

Moderate

5.0 – 7.9 mpy

(0.0254-0.12446 mm/y) High

(0.127-0.20066 mm/y)

5 – 10 mpy

High

8 – 15 mpy

(0.127-0.254 mm/y) Severe

(0.2032-0.381 mm/y)

> 10 mpy (0.254 mm/y)

Severe

> 15 mpy (0.381 mm/y)

To interpret the weight-loss coupon data in terms of the corrosion severity classification given in Table 3 as well as the corrosivity data depicted in Table 2, we resort to elementary statistics. For each of the oilfield water handling systems, the incidents of ‘Severe’ general and pitting corrosion during the period of 2010-2013 are presented in Table 4. Table-4: Summary of Corrosion and Pitting Rates of Different Fluid Streams S/N 1 2

Parameter General corrosion Rate (above 10 mpy) Pitting Rate (above 15 mpy)

Incidents of severe corrosion (%) Brackish Water

Recycle Water

Effluent Water

67

20

9

92

86

57

During the period, the locations prone to high and severe corrosion in these streams are monitored on a 45-day interval. Based on these results, the corrosion severity ranking of the water handling systems is in the following decreasing order: Brackish Water > Recycle Water > Effluent Water This is paradoxically the complete opposite of the corrosivity ranking. That is, there is no direct correlation between the analytical results from fluid sampling vis-à-vis weight-loss corrosion coupon results. This is a rather curious observation that might have been occasioned by the presence of corrosion inhibitor residual in all the oilfield water handling systems. Although an ©2014 by NACE International. Requests for permission to publish this manuscript in any form, in part or in whole, must be in writing to NACE International, Publications Division, 1440 South Creek Drive, Houston, Texas 77084. The material presented and the views expressed in this paper are solely those of the author(s) and are not necessarily endorsed by the Association.

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oilfield water-handling system might be corrosive, the continuous presence of a molecular layer of corrosion inhibitor on the internal pipeline surface negates the effects of corrosivity. Hence, bulk corrosivity of the oilfield water-handling system might be an inappropriate performance indicator in the presence of effective corrosion inhibitor. What then is responsible for the corrosion severity ranking noted above under the current production scenarios? It is perhaps occasioned by the order of susceptibility of the streams to Microbiologically Influenced Corrosion (MIC). Indeed, in an earlier paper5 the effect of bacteria population density on general and pitting corrosion was utilized to establish an asset integrity risk ranking in the following decreasing order: Brackish Water > Recycle Water > Effluent Water This is exactly the same order observed above. Consequently, bacteria population density, under the current production scenarios, is the key performance indicator. That is, effective and efficient corrosion mitigation in a bacteria-infected MIC-susceptible water-handling system may not be possible without an effective biocide even if corrosion inhibitor, oxygen scavenger and other treatment chemicals are adequate. A judicious combination of treatment chemicals is required for oil & gas companies to operate with greater cost effectiveness, efficiency, reliability and control of the state of corrosion integrity of oilfield water handling systems. Internal corrosion monitoring is therefore indispensable for pipeline integrity. SUMMARY AND CONCLUSION 1 2 3 4 5 6 7 8 9

Internal Corrosion Monitoring is indispensable for pipeline integrity Fluid chemistry is important for oilfield corrosivity trending. Based on the fluid chemistry under the current production scenarios, the corrosivity ranking of the oilfield water handling systems decreases in the following order: Effluent Water > Recycle Water > Brackish Water. The incidents of severe general corrosion observed in Brackish Water far exceed those of Recycle and Effluent Water. The same is true for pitting corrosion. The corrosion severity ranking of the oilfield water handling systems decreases in the following order: Brackish Water > Recycle Water > Effluent Water. Under the current production scenarios, Brackish Water is less saline and more susceptible to microbial infestation and corrosion. The paradoxical observation that Brackish Water is characterized by the lowest fluid corrosivity and the highest corrosion severity could be ascribed to its MIC susceptibility. Corrosion inhibitor, in combination with other treatment chemicals without an effective biocide, is ineffective in a bacteria-infected MIC-susceptible water-handling system. Bacteria population density is the key performance indicator in a bacteria-infected MIC-susceptible water-handling system.


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REFERENCES 1. Olagoke Olabisi. “Corrosion Rate as Key Performance Indicator in the North Slope”. Material Performance, 52, 8 (2013) 2. Preparation, Installation, Analysis, and Interpretation of Corrosion Coupons in Oilfield Operations, NACE International, NACE RP0775-2005. 3. ASTM G1 – 03, “Standard Practice for Preparing, Cleaning, and Evaluating Corrosion Test Specimens,” American Society for Testing and Materials, PA, 2003 4. Field Monitoring of Bacteria Growth in Oil and Gas Systems, NACE International, NACE TM0194-2004 5. A. R. Al-Shamari, A. W. Abdul Wahab Al-Mithin, Olagoke Olabisi, & Ashok Mathew. “Developing a Metric for Microbiologically Influenced Corrosion (MIC) in Oilfield Water Handling Systems”. CORROSION/2013, Paper No. C2013-0002299, (Orlando, FL: NACE 2013) 6. A. Morshed, “Improving Asset Corrosion Management Using KPIs”. Material Performance. 47, 5 (2008)


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