1^ST^ QUARTERLY REPORT

FOR PERIOD ENDING APRIL 30, 2005

CONTRACT NUMBER: DTRS56-05-T-0005

R4567-01R

DEVELOPMENT OF AN ICDA METHODOLOGY

FOR LIQUID PETROLEUM PIPELINES

**[prepared for]{.smallcaps}**

U.S. DOT RSPA

Washington, DC

**[prepared by]{.smallcaps}**

CC TECHNOLOGIES LABORATORIES, INC.

Oliver C. Moghissi

Conchita Mendez

April 29, 2005[^1]

![](media/image1.png){width="0.5937007874015748in"
height="0.6354330708661418in"}

DISCLAIMER

This report documents the work performed by CC Technologies
Laboratories, Inc. (CC Technologies) for U.S. DOT RSPA. Neither CC
Technologies nor any person acting on behalf of CC Technologies:

\(1\) assumes any liability for consequences or damages resulting from
the use, misuse, or reliance upon the information disclosed in this
report.

\(2\) makes any warranty or representations that the use of any
information, apparatus, method, or process disclosed in this report may
not infringe on privately-owned rights.

# aCTIVITIES/dELIVERABLES

> All project tasks are presently on schedule. Individual tasks are
> listed below, and this quarterly report serves as a payable milestone.
>
> Project Tasks: SCH Date CMPL Date

1)  Develop Concept 2/28/2005 2/28/2005

    a.  Literature Survey

    b.  Company Practices

    c.  Corrosion Prioritization Methods

2)  Enumerate Factors Influencing Corrosion Distribution 3/31/2005
    3/31/2005

    a.  Generate List of Factors

    b.  Interview Operators

    c.  Project Meeting to Discuss Factors

-   First Quarterly Status Report -- Payable Milestone 4/30/2005
    4/30/2005

CONTENTS

Page

[aCTIVITIES/dELIVERABLES 3](#activitiesdeliverables)

[Technical Status 5](#technical-status)

[Concept Development 5](#concept-development)

[Literature Survey 6](#literature-survey)

[Company Practices 7](#company-practices)

[Factors Influencing Corrosion Distribution
7](#factors-influencing-corrosion-distribution)

[Preliminary Summary on Flow Effects
8](#preliminary-summary-on-flow-effects)

[Business Status 15](#business-status)

[Schedule 16](#schedule)

[Payable Milestone and Spending 16](#payable-milestone-and-spending)

[Issues, Problems, or Challenges 16](#issues-problems-or-challenges)

[Plans for Future Activity 17](#plans-for-future-activity)

[Public page 17](#public-page)

# Technical Status

The goal of this project is to develop an ICDA method applicable to
pipelines transporting liquid petroleum products (e.g., crude oil,
fuels) so that liquid pipeline operators can utilize DA for integrity
assessments. To distinguish it from other ICDA methods, it is referred
to as LP-ICDA.

## Concept Development

Development of the LP-ICDA concept was task 1 of the project. This
section outlines the concept and serves as documentation of task 2
completion. Tasks 1a and 1b to perform a literature survey and review
company practices are complete, and task 1c is to summarize the results
of 1a and 1b. Summaries of the literature and company practice are
listed as subheadings below.

The basis of DA is that 1) a mechanism for susceptibility is identified
(i.e., pre-assessment), 2) a property associated with this mechanism is
used as a basis for detecting susceptibility (indirect inspections), 3)
direct observations are made to verify the correlation between the
property and mechanism (direct examinations), and 4) corrections are
made for any discrepancies (i.e., post-assessment).

The framework for all DA methods is a four step process:

1)  Pre-Assessment -- The data necessary to perform DA is collected, and
    an analysis of DA feasibility is performed. This step also includes
    planning for the assessment, including dividing pipeline segment
    into regions and determining the methods by which the remaining
    steps will be conducted.

2)  Indirect Inspections -- Measurements are taken or calculations are
    performed specific to the pipeline regions and segment of interest.
    The results are used to prioritize locations along a pipeline
    segment for susceptibility to corrosion.

3)  Direct (or Detailed) Examinations -- The pipe is examined at
    locations prioritized to have the highest likelihood of corrosion
    along a pipeline region or segment. The examination must have
    sufficient detail to determine the existence, extent, and severity
    of corrosion. If possible, direct physical examination of the pipe
    surface is performed, but examination of the internal surface of a
    pipe may involve non-destructive examination methods sufficient to
    characterize internal defects.

4)  Post-Assessment -- Analysis of the indirect and direct examination
    data is performed to determine overall pipeline integrity,
    prioritize repairs, and set the interval for the next future
    assessment.

For liquid product transmission pipelines, water that is normally
entrained in the hydrocarbon phase can settle to the bottom of the line.
This water can accumulate locally (i.e., upstream of inclines) and will
remain there allowing corrosion to occur until swept out by high flow
velocities (or a pig). If these locations can be predicted, they can
serve as local examination points. If these locations are free from
corrosion, other locations less likely to have accumulated water can
also be considered free from corrosion. Previous work exists to predict
the critical velocity (given other factors such as specific gravity,
viscosity, pipe diameter, etc.) at which water is entrained. However, it
does not predict where water would accumulate.

To further prioritize internal corrosion, other factors affecting the
distribution of corrosion likelihood along a pipeline segment must be
identified and considered.

### Literature Survey

No previous work directly addresses the distribution of corrosion in a
hydrocarbon-liquid-packed pipeline. However, a large body of general
work exists on oil-water flows, primarily in horizontal pipelines (e.g.,
literature review of Shi[^2]). Most of this work focuses on flow
assurance (e.g., predicting pressure drop) without consideration of its
effects on corrosion. Work also exists on entrainment of water.
Entrainment of water can be used as a criterion for prioritizing risk of
individual pipeline segments because corrosion is unlikely where water
is not contacting the pipe wall. A critical velocity exists (for each
pipeline, product and operating condition), below which water will not
be entrained in flowing oil (i.e., water will settle out on the bottom
of a horizontal pipeline). At higher velocities, water droplets are
entrained so that the water is swept away. Previous work exists to
predict when water is entrained, but it does not predict where water
would accumulate. Finally, no previous work has been published on the
multiple environmental factors (i.e., besides the presence of water)
that might affect the distribution of corrosion within a pipeline.

The results of the literature survey relevant to the proposed LP-ICDA
method are included in the section on flow effects further in this
report.

### Company Practices

Company practices include two concepts related to ICDA. The first is to
prioritize (or remove) the threat of internal corrosion based on
critical velocity to entrain water in a hydrocarbon. The second is to
inspect 'dead-legs' for corrosion.

-   Several operators use liquid hydrocarbon throughput velocities as a
    basis for prioritizing the likelihood of internal corrosion. This is
    done on a segment basis within a system rather than to prioritize
    corrosion within an individual segment. In one case, a large
    operator utilized a critical velocity (calculated from Wicks and
    Fraser[^3]) as a criterion for corrosion susceptibility. However, in
    most cases it is done on an ad-hoc basis where lines with low flow
    are considered more likely to have internal corrosion than those
    with high flow. Typical response to reducing internal corrosion
    likelihood in low-flow lines includes maintenance pigging or
    chemical treatment.

-   For systems of low flow, or for facilities with pipe configurations
    resulting in low (or no) flow, it is common to perform inspections
    (or monitoring) at those locations to identify susceptibility to
    corrosion. The most common facility for this is at pumping stations
    where the many bends and other facility components that affect flow
    can result in areas where no flow exists. These are locations where
    water can settle and not be removed by entrainment. In addition,
    efforts to avoid areas of no-flow are made in the design stage of
    liquid petroleum pipeline related facilities. No operators were
    found to use this approach for mainline sections of pipe (i.e., the
    primary application for LP-ICDA).

## Factors Influencing Corrosion Distribution

Developing a list of (i.e., enumerating) factors influencing corrosion
distribution was task 2 of the project. This section lists the factors
and serves as documentation of task 2 completion. This task was
completed by generating an initial list (i.e., task 2a), interviewing
operators for input on the list (i.e., task 2b), and discussing the
factors at project meetings (i.e., task 2c).

Since the goal of ICDA is to prioritize the likelihood (or severity) of
corrosion with respect to location, factors that affect the distribution
of internal corrosion within a liquid petroleum pipeline were
considered. They include:

-   Flow

-   Emulsion breaking

-   Corrosion inhibitors

-   Changes in dissolved gas concentrations (e.g., CO~2~ and H~2~S)

-   Changes in free water composition over distance, including organic
    acids

-   Deposits including paraffin (i.e., wax) and asphaltenes

-   Top-of-line corrosion in areas where the line is not liquid-packed

Input on the completeness and validity of these factors was solicited at
several meetings related to the project. Through pipeline operator
input, the factor of top-of-line corrosion was identified.
Coincidentally, this effect was identified through a separate project
under contract between CC Technologies and the operator, so the
information will be shared to the benefit of this project.

### Preliminary Summary on Flow Effects

*The summary on flow effects is work in progress and represents the
start of task 3 of the project. It is likely that final project
deliverable will not reflect the following summary.*

In liquid petroleum pipelines, the hydrocarbon phase is considered
non-corrosive, and corrosion is only possible with the presence of
water. The following scenarios are to be taken into account during the
indirect inspection step of the ICDA methodology for pipelines carrying
liquid petroleum with less than 1% of water.

Scenario 1

Free water (less than 1%) is transported entrained in the hydrocarbon
phase. Changes during transportation may cause water originally
entrained to be separated going to Scenario 2.

Scenario 2

Free water is transported on the bottom of the pipeline (stratified
flow). Changes in topography may cause water to be accumulated in
certain locations.

Scenario 3

Percentage of water increases eventually for any reason (upsets). An
analysis of this scenario should determine the possibility of this
additional water to exit the system on a relative short period of time
(not affecting the pipeline integrity) or to accumulate in certain
locations (Scenario 2).

The following summary outlines equations in the literature to estimate
water entrainment. System parameters will be needed to predict flow
effects. Some are typically known, and others may need to be estimated.
A list of these parameters is as follows:

-   **Fluid parameters**:

> Water phase: volume flow of water,$Q_{w}$, (or superficial gas
> velocity of water, $U_{\text{sw}}$).
>
> Mixture oil-water: density of the oil-water mixture,$\rho_{m}$
>
> Hydrocarbon or oil phase: volume flow of oil,$Q_{o}$, (or superficial
> oil velocity); oil viscosity, $\eta_{o}$; surface tension, $\sigma$;
> oil density, $\rho_{o}$.

-   **Geometric Parameters**: pipe diameter, D; cross sectional area of
    the pipe, A; pipeline inclination, $\theta$.

With this input parameters some parameters can be calculated:

-   The maximum droplet size that can be sustained by the flow without
    further breakup, $d_{\text{max}}$.

-   The critical droplet size, $d_{\text{crit}}$. Droplets larger than
    this value will separate out from the two-phase flow dispersion
    either due to gravity forces, predominant in horizontal flow, or due
    to deformation and "creaming", typical in vertical flow.

From these calculations a criterion needs to be applied to conclude if
at the conditions of the system, water phase is entrained on the
hydrocarbon phase. The final criterion for water entrainment into the
hydrocarbon or oil phase is established in BraunerError: Reference
source not found. The transition from stratified flow to stable
water-in-oil dispersion takes places when the oil phase turbulence is
intense enough to maintain the water phase broken up into droplets not
larger than $d_{\text{max}}$which has to be smaller than the a critical
droplet size, $d_{\text{crit}}$, causing droplet separation
($d_{\text{max}} \leq d_{\text{crit}}$). The following discussion
contains equations to calculate $d_{\text{max}}$and $d_{\text{crit}}$.

***Critical velocity for water entrainment***

The critical velocity is that above which oil is entrained by flowing
water phase. The critical velocity is obtained by following the models
proposed by Wicks and Fraiser,[^4] Brauner,[^5] Barnea,[^6] and Cai et
al.[^7] If the input water velocity is smaller than the critical
velocity, the flow pattern will be stratified flow for a given flow
conditions, otherwise, the flow pattern will be oil continuous dispersed
flow in the horizontal and downward inclined pipelines. The factors
governing formation of water droplets and their sizes are oil and water
specific gravities, interfacial tension between the oil and water, oil
viscosity, pipe diameter, and oil velocity. Because stratified flow does
not exist in the vertical and most angles in upward inclined pipelines,
if the input water velocity is smaller than the critical velocity, the
flow pattern will be unstable oil continuous dispersed flow.

***Maximum droplet size***

Water is entrained by the flowing oil phase in the form of droplets, and
it is important to know the maximum droplet size that can be sustained
by the flow without further breakup.

Two sets of equations are used to determine the maximum droplet size
depending on the characteristics of the water dispersion in the oil
phase. The first approach described in this document is for dilute
dispersions. Under the dilute flow conditions the water droplets
entrained in the oil phase act independently, fully suspended in the
continuous hydrocarbon phase, and fluid-droplet forces dominate.

For dilute dispersions, defined as those where

$\left( 1 - \varepsilon_{w} \right)\frac{\rho_{m}}{\rho_{o}} \approx 1$
(1)

Where

$\varepsilon_{w}$ is the in-situ water cut (the disperse phase in this
case)

$\rho_{m}$ is the density of the oil-water mixture

$\rho_{o}$ is the density of the continuous phase (in this case oil)

the, maximum droplet size in pipe flow, $d_{\text{max}}$, can be
expressed according to BraunerError: Reference source not found as:

  ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
  $\left( \frac{d_{\text{max}}}{D} \right)_{\text{dilute}} = 1\text{.}\text{88}\left\lbrack \frac{\rho_{o}\left( 1 - \varepsilon_{w} \right)}{\rho_{m}} \right\rbrack^{- 0\text{.}4}\text{We}_{o^{- 0\text{.}6}}\text{Re}_{o^{0\text{.}\text{08}}}$
  (2)

  ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

If

$$1\text{.}8\text{Re}_{o^{- 0\text{.}7}}$$

Notice the subscript to refer to dilute dispersion.

Here:

D: pipe diameter

$\varepsilon$: in-situ water cut

$\text{We}_{o}$: Weber number of oil phase

$\text{Re}_{o}$: Reynolds number of oil phase

$\varepsilon_{w} = \frac{U_{\text{sw}}}{U_{\text{sw}} + U_{\text{so}}}$
(3)

$\text{We}_{o} = \frac{\rho_{o}\text{DU}_{o}^{2}}{\sigma}$ (4)

$\text{Re}_{o} = \frac{\rho_{o}\text{DU}_{o}^{2}}{\eta_{o}}$ (5)

$U_{o} = U_{\text{sw}} + U_{\text{so}}$ (6)

$U_{o}$: oil velocity (continuous phase in this case)

$U_{\text{sw}}$: superficial water velocity ($U_{\text{sw}} = Q_{w}A$),
$Q_{a}$is the volume flow of water and A is the cross sectional area of
pipe.

$U_{\text{so}}$: superficial oil velocity ($U_{\text{so}} = Q_{o}A$),
$Q_{o}$is the volume flow of oil

$\eta_{o}$: oil viscosity

$\sigma$: surface tension of the oil

The Weber number represents the ratio between the external force that
tends to deform the drop, and the counteracting surface tension force
($\text{We}_{\text{crit}} = \frac{\tau \cdot d_{\text{max}}}{\sigma}$).
The Weber number was used by Kolmogorov [^8] and Hinze [^9] for
emulsification studies in turbulent flow. Using dimensional arguments
they show that the slitting of a drop (or a bubble) in turbulent flow
depend on the critical Weber number.

Although the turbulent field in pipe flow is not homogeneous and
isotropic, Eq. 2 has been proven to yield a good prediction of the
maximal drop size in the flow of dilute dispersions for a variety of
two-liquid systems, as long as $d_{\text{max}} < 0\text{.}1D$. For
liquid systems, where the density of the continuous and disperse phases
is approximately the same, this approximation is valid for
$\varepsilon_{w}\text{<<}1$.

At this point the following input parameters were identified:

Fluid parameters:

> Water phase: $Q_{w}$
>
> Mixture oil-water: $\rho_{m}$
>
> Hydrocarbon or oil phase:$Q_{o}$, $\eta_{o}$, $\sigma$, $\rho_{o}$

Geometric Parameters: D, A

When the dispersion cannot be considered dilute which mean droplets of
water entrained in the hydrocarbon phase are not fully suspended and
there is much interaction between them, a dense dispersion approach
should be considered. This approach may apply if there is an eventual
increase in the water cut for any reason or if there is a large
difference between the oil-water mixture density and the oil density.

Under such conditions, the flow rate of oil phase $Q_{o}$should carry
sufficient turbulent energy to disrupt the tendency of the water
droplets, flowing at a rate $Q_{w}$, to coalesce. Brauner Error:
Reference source not found pointed out that the rate of surface energy
production in the coalescing water phase is proportional to the rate of
turbulent energy supply by the flowing oil phase:

$\left( \frac{\rho_{o}U^{'2}}{2} \right)Q_{o} = C_{H}\frac{4\sigma}{d_{\text{max}}}Q_{w}$
(7)

where:

$Q_{o} = \frac{\pi}{4}D^{2}U_{\text{so}}$ (8)

$Q_{w} = \frac{\pi}{4}D^{2}U_{\text{sw}}$ (9)

$U^{'2} = 2\left( \text{ed}_{\text{max}} \right)^{\frac{2}{3}}$ (10)

$C_{H}$ is a constant of the order of 1. $U^{'}$denotes the turbulent
kinetic energy.

In the isotropic and homogeneous turbulence, the turbulent kinetic
energy can be related to the rate of turbulent energy dissipation, e:

$e = \frac{4{\tau U}_{o}}{{D\rho}_{o}\left( 1 - \varepsilon_{w} \right)} = \frac{2U_{o}^{3}}{D}\frac{\rho_{m}}{\rho_{o}\left( 1 - \varepsilon_{w} \right)}$
(11)

Substituting the equations (9) and (11) into (7) yields

  ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
  $\left( \frac{d_{\text{max}}}{D} \right)_{\text{dense}} = 2\text{.}\text{22}C_{H}^{0\text{.}6}\left( \frac{\rho_{o}U_{o}^{2}D}{\sigma} \right)^{- 0\text{.}6}\left( \frac{\varepsilon_{w}}{1 - \varepsilon_{w}} \right)^{0\text{.}6}\left\lbrack \frac{\rho_{m}}{\rho_{o}\left( 1 - \varepsilon_{w} \right)}f \right\rbrack^{- 0\text{.}4}$
  (12)

  ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Where the subscript dense denotes the dense oil-water dispersion.

To include the dense dispersion analysis we would need to know the same
parameters needed for the dilute dispersion analysis.

Given a water-oil fluid system and operational conditions, the maximum
droplet size that can be sustained is the larger of the two values
obtained via the dilute or the dense dispersion approach (eq. 2 and 12),
which can be considered as the worst case for a given oil-water system:

$\left( \frac{d_{\text{max}}}{D} \right) = \text{Max}\left\{ \left( \frac{d_{\text{max}}}{D} \right)_{\text{dilute}},\left( \frac{d_{\text{max}}}{D} \right)_{\text{dense}} \right\}$
(13)

***Critical droplet size***

Droplets larger than a critical droplet size, $d_{\text{crit}}$,
separate out from the two-phase flow dispersion either due to gravity
forces, predominant in horizontal flow, or due to deformation and
"creaming" typical for vertical flow (BarneaError: Reference source not
found).

-   Gravity effect: Critical droplet diameter above which separation of
    droplets due to gravity, $d_{\text{cd}}$, takes place can be found
    via a balance of gravity and turbulent forces as (Barnea Error:
    Reference source not found):

  --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
  $\left( \frac{d_{\text{cd}}}{D} \right) = \frac{3}{8}\frac{\rho_{o}}{|\Delta\rho|}\frac{\text{fU}_{o}^{2}}{\text{Dg} \cdot \text{cos}(\theta)} = \frac{3}{8}f\frac{\rho_{0}}{\Delta\rho}\text{Fr}_{o}$
  (14)

  --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Where Froude number is defined as:

$\text{Fr}_{o} = \frac{U_{o}^{2}}{\text{Dg} \cdot \text{cos}(\theta)}$
(15)

$$|\Delta\rho| = \left| \rho_{o} - \rho_{w} \right|$$

$\theta$: inclination of the pipeline

g: gravity constant

$f$: friction factor
($f = 0\text{.}\text{046}\text{/Re}_{o}^{0\text{.}2}$)

This effect is predominant at low pipe inclinations i.e. in horizontal
and near-horizontal flows.

-   Creaming: is defined as the separation of phases of an emulsion with
    the lighter phase on top and denser phase on bottom. The critical
    droplet diameter above which drops are deformed and "creamed",
    $d_{c\sigma}$, leading to migration of the droplets towards the pipe
    walls in vertical and near-vertical flows, can be calculated with
    the equation proposed by Brodkey[^10]:

$\left( \frac{d_{c\sigma}}{D} \right) = \left\lbrack \frac{0\text{.}4\sigma}{\left| \rho_{o} - \rho_{w} \right|\text{gD}^{2} \cdot \text{cos}(\beta)} \right\rbrack^{0\text{.}5}$
(16)

$\beta = |\theta|$ if $|\theta| < \text{45}^{o}$

The critical diameter, $d_{\text{crit}}$, can then be conservatively
estimated for any pipe inclination according to the suggestion made by
BarneaError: Reference source not found:

  --------------------------------------------------------------------------------------------------------------------------------------
  $\frac{d_{\text{crit}}}{D} = \text{Min}\left\{ \left( \frac{d_{\text{cd}}}{D} \right),\left( \frac{d_{c\sigma}}{D} \right) \right\}$
  (17)

  --------------------------------------------------------------------------------------------------------------------------------------

In addition to the parameters needed to estimate the maximum droplet
size, the calculation of critical droplet size requires the inclination
angle of pipeline.

The final criterion for water entrainment into the hydrocarbon or oil
phase is established in BraunerError: Reference source not found. The
transition from stratified flow to stable water-in-oil dispersion takes
places when the oil phase turbulence is intense enough to maintain the
water phase broken up into droplets not larger than
$d_{\text{max}}$which has to be smaller than the a critical droplet
size, $d_{\text{crit}}$, causing droplet separation
($d_{\text{max}} \leq d_{\text{crit}}$)

# Business Status

A project deliverable was to discuss factors influencing the
distribution of corrosion at a project meeting. Several project-related
meetings were held that served to provide the forum for discussion:

-   The NACE task group to develop a standard recommended practice met
    on April 7^th^. The chair and vice-chair were changed so that Tanis
    Lindberg (who is the industry project manager for this project) is
    now the chair. The previous chair was Mark Mateer who will now serve
    as vice-chair. Mark Mateer was formerly employed by Shell Pipeline
    but is now an employee of CC Technologies.

-   Two meetings were held under PRCI funding prior to the start of the
    performance period for this OPS project. They are 1) on Tuesday,
    December 14^th^ at Duke Energy, and 2) at a PRCI Corrosion and
    Inspection meeting during the week of January 20^th^.

-   A meeting with the OPS technical representative was held in Denver
    on April 19^th^.

-   Future meetings related to the project will be held

    -   The week of June 1^st^ (as part of the PRCI Corrosion &
        Inspection meeting

    -   Tuesday June 14^th^ (as part of an INGAA coordinated ICDA
        Industry Meeting)

# Schedule

> All project tasks are presently on schedule and future tasks are
> planned according to schedule. Completed individual tasks are listed
> below.
>
> Project Tasks: SCH Date CMPL Date

1)  Develop Concept 2/28/2005 2/28/2005

    a.  Literature Survey

    b.  Company Practices

    c.  Corrosion Prioritization Methods

2)  Enumerate Factors Influencing Corrosion Distribution 3/31/2005
    3/31/2005

    a.  Generate List of Factors

    b.  Interview Operators

    c.  Project Meeting to Discuss Factors

-   First Quarterly Status Report -- Payable Milestone 4/30/2005
    4/30/2005

# Payable Milestone and Spending

This 1^st^ quarterly report serves as a payable milestone. Federal
payment spending on the project through end of April is approximately
\$28,180. This amount exceeds the payable milestone of \$16,113 because
work on the next payable milestone is already in progress. Partner
cost-sharing contributions are on-budget.

# Issues, Problems, or Challenges

No serious issues, problems, or challenges have been encountered to
date. However, it was discovered during the course of this work, that
the presence of water might be the dominant corrosion susceptibility
prioritization factor (i.e., analogous to the dry-gas ICDA approach).
Therefore, a flow-modeling approach to predict water accumulation
locations will be explored. In this case, some of the existing project
funds may need to be used for a subcontractor having specific experience
with oil/water flow (and low water volumes). The total project cost
would be unaffected.

# Plans for Future Activity

Plans for future activity follow the existing technical and deliverable
milestone schedule. Second quarter plans are to evaluate each of the
factors affecting corrosion distribution in detail. Initial emphasis
will be placed on flow effects and comparison of the results with
inspection data.

# Public page

This entire report may be made public.

[^1]: Editorial revisions made June 10^th^, 2005

[^2]: H. Shi, 'A Study of Oil-Water Flows in Large Diameter Horizontal
    Pipelines,' Doctoral Dissertation, Ohio University, 2001.

[^3]: M. Wicks and J.P. Fraser, 'Entrainment of Water by Flowing Oil,'
    Materials Performance, NACE International, Houston, TX (May, 1975).

[^4]: M. Wicks and J.P. Fraser, 'Entrainment of Water by Flowing Oil,'
    Materials Performance, NACE International, Houston, TX (May, 1975).

[^5]: Brauner, N., The prediction of dispersed flowa boundaries in
    liquid-liquid and gas-liquid systems, Int. Journal of Multiphase
    Flow, 27 (2001), 885-910.

[^6]: Barnea, D., A unified model for predicting flow-pattern
    transitions for the whole range of pipe inclinations**,** Int.
    Journal of Multiphase Flow, Volume 13, Issue 1, (1987), 1-12.

[^7]: Nesic, S., Cai, J., de Waard, C., Modeling of water wetting in
    oil-water pipe folw, CORROSION/2004, Houston, TX, Paper No. 04663,
    (2004).

[^8]: Kolmogorov, A.N., On the breaking of drops in turbulent flow,
    (1949), in Ref 1.

[^9]: Hinze, J., Fundamental of the hydrodynamic mechanism of splitting
    in dispersion processes, AIChE J., 3, (1955), 289-295, in Ref. 1.

[^10]: Brodkey, R.S., [The Phenomena of Fluid Motions]{.underline},
    Dover Publications; (1995).