United States Office of EP& 570/9-85-OOS
Environmental Protection Drinking Water November 1985
Agency Washington, D.C. 20460
Underground Injection Control
&EPA Guidance Document on
Evaluation of Injection
Well Manifold Monitoring
Systems
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ACKNOWLEDGMENT
This document was prepared by Woodward—Clyde Consultants for
the U. S. Environmental Protection Agency under Contract No.
4W—2548—NTSX for Mr. Thomas E. Belk, Chief of the Underground
Injection Control Branch. Mr. A. Roger Anzzolin was the EPA
Project Officer. Mssrs. Paul S. Osborne and Gus Stolz,
Region VIII in Denver, Krishna Kamath, Region V in Chicago,
and Mario Salazar, Headquarters, provided many valuable
comments and an excellent review of this document. Mr.
Charles Kleeman, Region III in Philadelphia, prepared the
original scope of work and also provided valuable comments
and review of the final document. Mr. Robert B. Murphy of
of Woodward—Clyde Consultants of Englewood, Colorado provided
the technical support in the preparation of this document.
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TABLE OF CONTENTS
PAGE
1 • 0 INTRODUCTION 1
1 • 1 PURPOSE OF THIS DOCUMENT 1
1.2 MANIFOLD MONITORING 1
2.0 STATE OF THE ART OP EXISTING MANIFOLD MONITORING SYSTEN 2
2.1 GENERAL 2
2.2 INJECTION WELLS MONITORING 4
2.2.1 Flow Metering — General 5
2.2.2 Pressure Differential Meters 5
2.2.3 Rotating Mechanical Meters 6
2.2.4 Pressure Metering 7
3.0 INDIVIDUAL WELL MONITORING VS. MANIFOLD MONITORING 8
3.1 INTRODUCTION 8
3 • 2 LEAXS IN TUBULAR GOODS OF WELL C S) 1 0
3.2.1 Individual Injection Well Monitoring 10
3.2.2 Manifold Monitoring 11
3.3 COMPLIANCE WITH INJECTION PRESSURE LIMITATIONS 14
3.3.1 Individual Well Monitoring 14
3.3.2 Manifold Monitoring 14
3.4 WELL INJECTIVITY 16
3.4.1 Individual Well Monitoring 17
3.4.2 Manifold Monitoring 17
3.5 COMPATIBILITY OF INJECTION FLUIDS WITH
TUBULAR GOODS AND INJECTION FORMATION 18
3.5.1 Individual Well Monitoring 18
3.5.2 Manifold Monitoring 19
4.0 VALIDITY AND SENSITIVITY OF MANIFOLD DATA 19
4.1 INTRODUCTION 19
4.2 FL M DATA 20
4.2.1 Validity 20
4.2.2 Sensitivity 20
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TABLE OF CONTENTS
(Continued)
PAGE
4.3 INJECTION PRESSURE 21
4.3.1 Validity 21
4.3.2 Sensitivity 21
4.4 NATURE OF INJECTED FLUID 22
5.0 EVALUATION CRITERIA 22
5.1 INTRODUCTION 22
5.2 APPROACH TO CRITERIA DEVELOPMENT 25
REFERENCES
FOLLOWING
PAGE
FIGURE 1 - SCHEMATICS OF TYPICAL MULTIPLE POINT
INJECTION FACILITIES - CURRENT METERING PRACTICE 1
FIGURE 2 - SCHEMATICS OP MULTIPLE POINT INJECTION FACILITIES
MANIFOLD MONITORING 2
FIGURE 3 - THREE COMMON PRESSURE DIFFERENTIAL FLOW METERS 5
FIGURE 4 - SCHEMATIC OF PRESSURE DIFFERENTIAL FLOW METER 5
FIGURE 5 — SCHEMATIC OF THREE TYPES OF POSITIVE DISPLACEMENT METERS 6
FIGURE 6 - SCHEMATIC OF TYPICAL TURBINE FLOW METER 7
FIGURE 7 - LIMITS OF DETECTABLE FLOW RATE CHANGES FOR FLOW
OF VARIOUS ACCURACIES 12
FIGURE 8 - LIMITS OF DETECTABLE PRESSURE CHANGES FOR
PRESSURE GAGES OF VARIOUS ACCURACIES 12
FIGURE 9 - ENERGY DIAGRAM ACROSS A FLOW DIVIDING TEE 1 2
FIGURE 10 - ASSUMED AND ACTUAL ENERGY DIAGRAM FOR WELL HEAD
PRESSURE USING MANIFOLD PRESSURE 1 5
—ii —
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TABLE OF CONTENTS
(Continued)
PAGE
TABLE 1 - SUM 4ARY OF OPERATING CHARACTERISTICS OF
TYPICAL FLOW AND PRESSURE METERING DEVICES 9
APPENDIX A - ADDITIONAL FLOW MEASURING DEVICES
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1 • 0 INTRODUCTION
1 • 1 PURPOSE OF THIS DOCUM T
In the Underground Injection Control (UIC) regulations, owners and opera-
tors of Class II hydrocarbon storage and enhanced recovery wells are
allowed to monitor injection pressure, flow rate, cumulative volume and the
nature of the injected fluids on a field/project basis rather than on an
individual well basis through the use of manifold monitoring (40 CFR
Section 146.23 (bJ(5]). Such a monitoring system may be used in cases of
operations consisting of multiple injection facilities operating with a
common manifold. Separate monitoring systems for each well would not be
required provided that the owner/operator demonstrates to EPA’s
satisfaction that manifold monitoring is comparable- to individual well
monitoring. The purpose of this document is to develop technical guidance
and ancillary criteria to enable EPA personnel to evaluate the
effectiveness of such system proposals in meeting the regulatory
requirements.
1.2 MANIFOLD MONITORING
The use of multiple point injection facilities using a common manifold vary
in configuration from project to project. The basic system components
generally consists of an injection fluid source, an injection pump and a
pipe manifold to divide flow to each injection well. A schematic of
typical multiple point injection facilities is given on Figure 1 • Each
injection well is connected to the manifold by laterals. The entire
manifold may in some cases be located near the injection pump with
relatively long laterals to each injection well (Figure 1A). In other
cases the manifold may extend out to each injection well with relatively
short laterals (Figure 1B).
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Woodward.c*yde Consultants.
INJECTION WELL 2
INJECTION
WELL I
( A) SHORT MANIFOLD
MAN I FQLD.
LATERAL I
CHEMICAL QUALITY
OF INJECTION
FLUID MONITORER
(LOCATION VARIES) INJECTION
WELL I
PRESSURE AND
FLOW METERING
INJECTION
WELL 2
PRESSURE AND
FLOW METERING
( B) LONG MANIFOLD
MANIFOLD MONITORING SYSTEM
WITH INDIVIDUAL
WELL METERING
PRESSURE AND FLOW METERING
CHEMICAL QUALITY
OF INJECTION
FLUID MONITORER
(LOCATION VARIES)
WELL 3
‘PRESSURE AND
FLOW METERING
‘PRESSURE AND
FLOW METERING
LATERAL
INJECTION
WELL 3
FJG.I
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Monitoring of injection pressure, flow rate, cumulative volume and the
nature of injected fluids on an individual well basis requires that
instrumentation for each parameter measured be provided on the lateral pipe
to each well, usually located at the well head. The nature of injected
fluids may be measured at any practical point in the system since no change
in the nature of injected fluids would be anticipated between the pump and
the injection well head.
Manifold monitoring of the injection pressure, flow rate, cumulative volume
and nature of injected fluid on a project basis would be done at a central
point upstream of the first inject.ton well and downstream of the in)ection
pump (Figure 2). A central monitoring point will reduce project cost of
purchasing, operating and maintaining monitoring equipment.
2.0 STATE OF THE ART OF EXISTING MANIFOLD MONITORING SYSTEM
2.1 GENERAL
The use of pipe manifolds for dividing and combining flows of liquids or
gases are found in many applications in industries today. Examples of
manifdlds used in combining flows include:
(a) Multiple pumps discharging to a single manifold;
(b) Exhaust manifolds on cars;
Cc) Oilfield collection manifolds.
Manifolds have also found many applications in dividing flows, they
include:
(a) Sprinkler irrigation systems;
(b) Underwater sewage discharge manifolds;
(c) Water and waste treatment flows into basins;
Cd) Tailing slurry deposition systems f or mining operations;
(e) Enhanced oil recovery.
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r4vL( h V ,i,ici, ri*c —
IN J E CT ION
PUMP-A
INJECTION
FLUID
SOURCE
MONITORING POINT FOR FLOW,
PRESSURE AND CHEMICAL
QUALITY OF NJECTION FLUID
LATERAL 3
I LATERAL 2
INJECTION INJECTION
WELL 2 WELL 3
( 0) LONG MANIFOLD
MANIFOLD MONITORING SYSTEM
WITHOUT INDIVIDUAL
WELL METERING
WELL 2
LATERAL 2
MANIFOLD
MONITORING POINT FOR
FLOW, PRESSURE AND
CHEMICAL QUALITY OF
INJECTION FLUID
LL
INJECTION
WELL I
( A) SHORT MANIFOLD
__ MANIFOLD
LATERAL
INJECT ION
WELL I
FIG. 2
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Since the injection well systems divide flow, we have limited our scope to
monitoring of divided flow manifolds.
The conclusions we drew from our literature review were that manifold
monitoring generally is undertaken as a means of obtaining data on total
system performance, typically total discharge. We did not locate a source
that suggested manifold monitoring was or could be used to provide flow and
pressure data on individual lateral lines.
Our review suggested that flow and pressure at discharge points on laterals
were estimated during the design process. The design of an irrigation
system for example is based on various assumptions, two of which are that
flow is constant or steady state and discharge is to the atmosphere. These
assumptions provide a means of estimating the flow to any sprinkler given
system data which is readily available and constant with time. Examples of
such data include pipe lengths, material of contruction and sprinkler head
elevation. Without these assumptions, flow to individual sprinklers could
not be estimated with any degree of accuracy.
Manifold monitoring systems, in general, are used to insure that required
pressures and flows designed into the systems are maintained for proper
operation. Typically, the ability to visually determine if the particular
system is operating properly also exists. If problems develop with a
sprinkler system, visual indicators generally exist. For example, if a
leak in a lateral were to develop, flow may stop from the sprinkler head or
a wet spot may develop on the surface of the ground for a buried lateral.
If a sprinkler becomes blocked, again flow stops from the sprinkler head,
thus indicating a problem. In most other manifold systems, similar types
of indicators exist, thus the need to estimate flow and pressure at the
discharge end of a lateral generally is not necessary.
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2.2 INIECTION WELLS MONITORING
Typically, in current oil field practice, monitoring of multiple point
injection systems is performed on an individual well basis. Most enhanced
recovery injection projects are monitored in this manner. The monitoring
systems generally measure pressure and flow at each well head. Injected
flow volume is either estimated from continuous flow records (flow rate
chart records) or by use of positive displacement type flow meters which
operate on a cumulative volume basis. In later discussions in this
document, flow rate and volume measurements are considered as basically
equivalent since the output from either can be integrated over time or
divided by time to get from flow rate to volume and vice versa. In
addition to monitoring at the well head, flow measuring devices are in some
cases installed on the manifold just downstream of the injection pump and
upstream of the first injection well lateral. A configuration such as this
provides a means of checking the cumulative total to the individual
wells. If significant differences are noted, steps can be taken to
determine the problem causing the differences.
The installation of a manifold meter to measure total flow to all injection
wells seems to be related to the complexity of the reservoir system and
operating expenses associated with injection fluid. Complex reservoirs
using expensive injection fluids are the types of operations where a
manifold meter would be utilized as a system check.
The flow and pressure measuring devices currently in use in manifold moni-
toring for enhanced recovery injections wells vary from system to system.
The economics of the enhanced recovery operation generally influence the
sophistication of the monitoring system and the metering devices used.
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2.2.1 Flow Metering — General
Modern flow measurement devices commonly found in enhanced recovery
injection well systems are generally either pressure differential meters or
rotating mechanical meters. The pressure differential type flow meter is
generally used in applications where injection rates are large; however, it
is also suitable for small injection operations.
2.2.2 Pressure Differential Meters
The pressure differential meter was for many years the only device
available for measuring volumetric flow rate in pipes with a reasonable
degree of accuracy. The most common types of pressure differenti .al meters
are the orifice meter, venturi meter and nozzle meter (Figure 3).
Each of these meters imposes a constriction to flow in a pipe. As flow
moves through a constriction it accelerates causing an increase in kinetic
energy and a corresponding decrease in pressure in accordance with the
principle of conservation of energy. For the differential meter shown in
Figure 4, flow passes through Section 1 of diameter d 1 and area A , at
average velocity ; then passes through section 2, of diameter d 2 and area
A 2 , at average velocity 2• By applying Bernoulli’s equation and the
principle of continuity, it can be shown that:
Q CA 2 2g(P 1 /w - P 2 /w)
where Q discharge, C a coefficient, A 2 = the area of the constriction,
P 1 and P 2 a pressure in pipe at Sections 1 and 2, w unit weight of
flowing fluid and g a acceleration due to gravity. The value of C varies
for the different differential flow meters.
Accuracy of a differential pressure flow meter ranges from about ±1 percent
if calibrated to about ±2 or 3 percent if uncalibrated.
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— _A - a - -
(C) NOZZLE
THREE COMMON PRESSURE
DIFFERENTIAL FLOW METERS
FLOWJ 1
(A) ORIFICE
(B) VENTURI
FIG. 3
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odward.Clyde Consultants.
V 1 AND V 2
= VELOCITY
P 1 AND P 2 = PRESSURE
W UNIT WEIGHT OF FLUID
g = VELOCITY DUE TO ACCELERATION
NOTE: CONSTRICTION IS SCHEMATIC AND WILL
VARY DEPENDING ON THE TYPE FLOW METER.
SCHEMATIC OF PRESSURE
DIFFERENTIAL FLOW METER
- -a -
2
V 2
2g
SECTION I SECTION 2
LEGEND
FIG. 4
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The orifice meter seems to be the most popular of the pressure differential
type meters. This is in part due to the low purchase price and low instal-
lation cost. The orifice meter does have higher head loss than the venturi
or nozzle type meters which would result in higher pumping cost over the
long run. Discussions of additional types of flow meters is given in
Appendix A.
2.2.3 Rotating Mechanical Meters
The rotating mechanical meters most commonly used in measuring injection
fluid flow are the positive displacement meter and the turbine meter.
Although its use is not any longer as common because of the development of
the two types of rotating mechanical meters mentioned above, the disc type
meter is still found on many injection systems. The rotating mechanical
meter measures total volume of flow or the volumetric flow rate.
2.2.3.1 Positive Displacement Meters.
Many types of positive displacement meters are available. These meters
fill the entire bore of the pipe through which flow is being measured. The
meter operates by separating the flow stream into pockets of known volume
and counting the number of pockets. The total number of pockets passing
the meter is accumulated either mechanically or in more modern installation
using digital readout equipment. Three common types of positive
displacement meters are the gear meter, oval wheel meter and the sliding
vane meter (Figure 5). The oval wheel is a type of gear meter.
Positive displacement meters are relatively accurate for a wide range of
flow rates, viscosity, pressure and temperature. Meter range is commonly
from 20:1 with accuracies of better than ±0.5 percent. Positive
displacement meters are generally most efficient for measuring flows and
volume on the order of 1000 to 30,000 barrel per day (bbl/day).
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Cc) SLIDING-VANE METER
Woodward.clvde Consuttants —
FLUID
POCKET
( b) “OVAL-WHEEL” TYPE
OF GEAR METER
FLUID POCKET
SCHEMATIC OF THREE TYPES
OF POSITIVE DISPLACEMENT METERS
( a) ONE TYPE OF GEAR
METER
FIG. 5
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2.2.3.2 Turbine Meter
The turbine me er is another type of rotating mechanical flow meter
(Figure 6). It consists of a short section of pipe in which a freely
spinning propeller is mounted. The propeller blade or an insert to the
propeller blade is a magnet. As flow pass through the section of pipe, it
rotates the propeller blade which generates a pulse as it passes a pickup
mounted in the wall of the pipe. The pickup is connected to a counter
which records the number of pulses and thus the volume of flow which has
passed the meter. The frequency of pulses is an indicator of volumetric
flow rate passing the turbine meter.
Although not as accurate as a positive displacement meter, the turbine
meter provides relatively good accuracy between about 10 and 100 percent of
its flow range. Typically accuracies on the order of ±1 percent or better
may be achieved if the meter is maintained and calibrated regularly.
2.2.3.3 Disc
The nutating disc meter is found on many injection flow monitoring sys-
tems. Sometimes referred to as a wobble meter because of its nutating
action, this meter has been used extensively for residential water
metering. The flow stream is separated into pockets by the nutating disc
chamber. The number of chamber volumes is counted using a gear linking
system connected to the chamber, thus obtaining volumetric flow rate. This
type meter generally is accurate to about ±2 percent for measuring flows
from about 100 bbl/day to 5000 bblfday. A summary of flow meter operating
characteristics is given on Table 1.
2.2.4 Pressure Metering
Common types of pressure meters in use with enhanced recovery injection
wells are the Bourdon Gauge and the pressure transducer. The Bourdon Gauge
is the most common of these pressure measuring devices.
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clyde Consultants..
SCHEMATIC OF TYPICAL
TURBINE FLOW METER
- E LECTRO M AG NET IC
PIcx-uP
TURBINE ROTOR BLADES)
BEARING HOUSING AND
SUPPORT VANES
FIG. 6
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2.2.4.1 Bourdon Gauges
A normal Bourdon gauge consists of a metal tube with an oval cross-section
formed into a semicircular shape. Generally the inside of the tube is
connected to the source of pressure to be measured with the exterior
exposed to atmospheric pressure. When the pressure on the inside of the
tube is greater than that on the outside, the tube tends to straighten.
The amount of straightening is a function of the difference between the
inside and outside pressure on the tube. The tube is connected by a
linkage system which converts deflection of the tithe rotation of a dial.
The accuracy of the bourdon tube pressure gauge is on the order of ±3 per-
cent or better.
2.2.4.2 Transducers
The transducer type of pressure sensing device consists of a metal dia-
phragm connected to the pressure source to be measured. The pressure on
the diaphragm causes a deflection which is proportional to the pressure.
Deflection of the diaphragm is monitored by a strain gauge or variable
capacitance device which produces an electrical analogue proportional to
the pressure. The accuracy of this type of gauge is on the order of
±1 percent or better. A summary of pressure gauge operating characteris-
tics are given on Table 1.
3.0 INDIVIDUAL WELL MONITORING VS. MANIFOLD MONITORING
3.1 INTRODUCTION
The following section addresses the viability of manifold monitoring of
injection pressure, flow rate, cumulative volume, and nature of injected
fluids as compared to the adequacy of individual well monitoring in
determining the following:
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TABLE 1
SUMMARY OF OPERATING CHARACTERISTICS OF
TYPICAL FLOW AND PRESSURE METERING DEVICES
Meter Basis of
Type Operation Accuracy Range Comments
Flow Metering
Pressure Differential Meters Flow constriction 1% calibrated orifice — Low Price
Low installation cost
Orifice 2-3% uncalibrated High head 1088
Venturi
Nozz ].e
Rotating Mechanical Meters Volume of Flow
Positive Displacement Counts known volume ± 0.2% 20:1 Used in 1,000 to
30,000 bbl/day
Gear
Oval Wheel
Sliding Vane
Turbine Frequency of pulses Good—between 10:1 Not as accurate as
10 — 100% of range positive displacement
± 1% if maintained
Disc
(wobble meter) Chamber volumes ± 2% Typical Flow Range
Used from 100 to
5000 bbl/day
Pressure Metering
Bourdon Guage (tube) Pressure deflection ± 3% or better
of tube
Transducers Pressure deflection ± 1% or better
on diaphragm
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1 • Leaks in the tubular goods of the wells;
2. Compliance with injection pressure limitations;
3. Compatibility of injection fluids with tubular goods and the
injection formation; and
4. Injectivity of the well.
The p,roces8 of evaluating whether individual well monitoring is comparable
to manifold monitoring will consider only those parameters from the
following list: (1) flow rate; (2) cumulative volume; (3) pressure; arid
(4) the nature of the injected fluid, which may impact the particular
determination. For example, the nature of injected fluid whether monitored
on an individual well or manifold basis, would riot impact the determination
of leaks in tubular goods. Therefore, only flow rate, cumulative volume
and pressure would be used in evaluating the adequacy of manifold tnoni-
toting in determining leaks in tubular goods.
3.2 L2AKS IN TUBULAR GOODS OF WELL(S)
3.2.1 Individual In)ection Well Monitoring
The detection of leaks in the tubular goods of an inj ection well. poten-.
tially can be accomplished using both pressure and flow data at the well
head. Indicators of leaks could be an unexplained increase in flow with a
corresponding drop in pressure at only a single well in a field. These
parameters can be used as indicators if formation pressure, assuming no
leak, changes in a relatively uniform mariner with similar responses from
other injection wells in the field. If the formation is such that pressure
and flow changes are formation related, then the use of these parameters
may riot provide a reliable indicator.
The detection of a leak using an individual well monitoring program depends
to a large extent on the size of the Leak and the accuracy of the pressure
and flow meter. In a case where the change in pressure due to the leak is
-10—
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10 pounds per square inch (psi) and the gauge is accurate to 50 psi, the
pressure drop potentially could go unnoticed. Using Figure 8, it can be
seen that for a gauge with a 5 percent accuracy operation at 1000 psi, a
change in pressure would fall below the limits of the accuracy of the gauge
and go undetected. Similarly, if the flow meter used were accurate to
50 barrels per day and the leak were 5 barrels per day, the change in flow
rate might also go unnoticed. To be useful in detecting leaks, the flow
meter, in particular, must have an accuracy such that it is capable of
detecting flows equal to what would be considered a significant leak.
Generally, accurate flow measurement is the best indicator of small leaks
and will be discussed further in regard to manifold monitoring.
3.2.2 Manifold Monitoring
The use of manifold monitoring may present a handicap in detecting leaks in
tubular goods of a well when compared to individual well monitoring. The
reason for this handicap is twofold. First, with manifold monitoring, if a
leak is detected, the location is unknown, since this method of monitoring
only provides data on the system as a whole and not the individual wells.
The second reason for this handicap lies in the potential ability of such a
system to detect small changes in flow caused by a leak. For example,
assume a system has 6 laterals coming of f from a manifold with 1/6 the
total assumed flow of 24,000 bbl/day going to each well. The flow meter
used to measure flow to the manifold is assumed to have an accuracy at
24,000 bbl/day of approximately ±0.5 percent or ±122 bbl/day. The flow
meters on a system with flow measurement at each well is assumed to have
the same accuracy at 4000 bbl/day or ±20 bbl/day. If a leak of approxi-
mately 30 barrels per day of fluid were to develop, the larger meter on the
manifold may not be able to detect it since 30 barrels per day is only
0.1 percent of the total flow. The smaller meter at each well should
detect this flow rate change because of its accuracy at the lower flow
range. For these systems to be comparable, the large meter would have to
have an accuracy at the rated flow of 24,000 bbl/day to detect a flow of
—11—
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Woodward.Clyde Consuftants
30 bbl/day. This would require the manifold flow meter to have an accuracy
of about +0.1 percent at the rated flow. An example plot of detectable
flow rate changes for meters of various accuracies is given on Figure 7.
Although Figure 7 does not extend out to the 24,000 bbl per day range, the
data is linear and can be extrapolated to give the results described in the
text.
Similarly, pressure changes as measured on the manifold would be so small
for the example given above, that current technology potentially could not
detect them. The reason for this is that small flow rate changes in an
individual well would result in small pressure changes on the overall
system.
Head loss through. the manifold system and laterals to each well is a
function of the flow velocity to approximately the second power. If, for
example, flow of 24,000 bbl/day were through a straight piece of 6—inch
diameter steel pipe 2000 feet long, the head loss would be 626 feet of
water or 27.1 psi. The loss through the same pipe for 24,030 bbl/day would
be approximately 62.76 feet of water or 27.2 psi. A difference of 0.1 psi
for a pressure gauge with an assumed range of 0 — 1 000 psi and an accuracy
at the rated pressure of +1.0 percent would be below detection limits. The
gauge would be accurate to 5 psi if the pressure in the system were
approximately 500 psi (500 psi x 1% = 5 psi). Figure 8 is a plot of
detectable pressure changes versus system pressure at the gauge for various
pressure gauge accuracies.
The manifold system is further complicated by pressure rises and drops
across lateral branches. In dividing flow, a pressure rise occurs in the
manifold after passing the lateral takeoff point (Figure 9S) due to
decreased velocity, when moving from the manifold into the lateral, a
pressure drop is generally noted (Figure 9A). In both cases, an overall
drop in total head is noted due to friction losses at the branch for either
path. The friction losses and pressure changes which are a function of
—12—
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NOTES:
1. METER ACCURACY ASSUMED LINEAR OVER RANGE OF FLOW RATES.
ACTUAL ACCURACY WILL VARY PARTICULARLY AT HIGH AND LOW
ENDS OF RANGE. AMOUNT OF VARIABILITY FUNCTION OF PARTICULAR
METER.
2. FOR FLOW RATE CHANGES TO BE DETECTABLE THE VALUE SHOULD BE
ABOVE THE ACCURACY LINE FOR SELECTED METER. FOR 6000 BBL/DAY
AT AN ACCURACY OF 5% FLOW CHANGE SHOULD BE GREATER THAN 300
BBL/DAY TO BE DETECTABLE.
500
‘U
a
‘U
4
c c
300
‘U
I . ,
z
4
x
(-)
‘U
200
0
-J
L
U i
-J
cc
4,
I -.
I -,
‘ U
I-
U,
a
0
C)
-4
5000 6000
METERED FLOW RATE IN BARRELS PER DAY
10000
I
I
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Woodward .cl’ de Co tauit .
NOTES:
1. METER ACCURACY
OF PRESSURES.
OVER PRESSURE
METER TO METER.
ASSUMED LINEAR OVER RANGE
METER ACCURACY MAY VARY
RANGE AND MAY VARY FROM
2. PRESSURE CHANGES TO BE DETECTABLE
SHOULD PLOT ABOVE THE METER ACCURACY
LINE FOR SPECIFIC METER AT THE MEASURED
PRESSURE.
LIMITS OF DETECTABLE PRESSURE
CHANGES FOR PRESSURE GAGES
OF VARIOUS ACCURACIES A*
I
F0
300
z
2
200
z
4
I
ICC
U,
w
3.
-J
4
I-
U
uJ
0
0
0 1000 2000 3000 4000 5000 6000
PRESSURE IN POUNDS PER SOUAPE INCH
7000
FIG. 8
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odward.ctyde Consuftants —
MANIFOLD
FLOW
1if. _ LATERAL
DATUM
( A) ENERGY DIAGRAM FROM POINT I TO 2
LEGEND
P 3 = PRESSURE IN PIPE
V 3 = FLOW VELOCITY
W = UNIT WEIGHT OF
FLOWING FLUID
g ACCELERATION DUE
TO GRAVITY
i 2
-J-
2c
W
BRANCH POINT
V HEAD LOSS h
‘• ‘ ‘ ‘ 6:i i V 3 2
I ! L2g
-CONDUIT
DATUM
( B) ENERGY DIAGRAM FROM I TO 3
ENERGY DIAGRAM ACROSS
A FLOW DIVIDING TEE
FLOW I•
V I
BRANCH POINT
HEAD LOSS hf
2
p 1
W
P 1 , P 2 ANO
V 1 , V 2 AND
FIG. 9
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flow to each branch can not be estimated with any degree of accuracy since
the distribution of flow cannot be estimated accurately. The conclusion to
be drawn from the example is that large pressure changes due to large
changes in flow are needed to be detectable given the economics and current
practice in pressure metering. Pressure data from an individual well or
manifold monitoring system by itself would be of very limited value in
detecting small leaks.
Although less likely to occur, the potential does exist for a single well
to plug and a leak to develop in another. In a situation such as this,
given the right set of circumstances, a very significant leak could occur
in conjunction with the plugging of another well and both might go
undetected en a system where manifold monitoring is used.
Another possibility is that a break or leak occurs in a buried lateral or
section of manifold. The leak again could go undetected if small enough
compared to the accuracy of the manifold monitoring flow meter. The
chances of discovering a leak such as this with individual well monitoring
is only possible if a manifold flow meter is also used as a master system
meter to monitor the whole system. In this case, the sum of the flows to
each would be less than the discharge measured at the master meter indi-
cating the potential existence of a leak.
In summary, the individual well monitoring system is only of marginal
adequacy in its ability to detect leaks in the tubular goods of a iell.
Small leaks may in many cases go undetected. The manifold monitoring
system is even Less likely to detect a leak. If a leak is detected from
manifold monitoring, its location is not known.
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3.3 COMPLIANCE WITH INU ECTION PRESSURE LIMITATIONS
3.3.1 Individual Well Monitoring
As discussed previously, when individual wells are monitored the pressure
and flow are measured at the well head, thus making verification of
compliance with injection formation pressure at the well bore relatively
straight-forward. The adequacy of this method is only limited to the
accuracy of the pressure and flow meters at the well head.
Assuming pressure and flow data at the well head are given, the pressure at
the injection formation can be computed using simple hydraulic techniques.
For purpose of our discussion regarding viability of manifold monitoring as
compared to individual well monitoring, we have assumed that, in either
case, if pressure and flow could be estimated or measured at the well head,
pressure at the injection formation could also be easily estimated. If
these data could not be measured or estimated at the well head, then
pressure and flow could not be estimated at the injection formation.
Therefore, the following discussion compares pressure as measured or
estimated at the well head and not at the injection formation.
3.3.2 Manifold Monitoring
Measurement of pressure and flow rate on a manifold upstream of the well
heads provides no direct means of estimating pressure at the well heads.
These data do provide the needed input for making a very approximate
indirect estimate of pressure at the individual well heads. Pressure
changes through the system are impacted by many factors including pipe
losses and minor losses (fittings, valves, etc.) which are all a function
of flow distribution.
If the total (available) energy at the manifold monitoring point were
converted to pressure energy (pressure head), this would represent the
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maximum pressure which could exist at an individual well head. As shown on
Figure bA, the total energy (H) at the manifold monitoring point can be
represented as:
H • Z +!. +
w 2g
where H — total (available) energy in feet, Z potential energy due to
position above an arbitrary datum in feet, P pressure in pounds per
square foot, w u unit weight of water in pounds per cubic foot, V = flow
velocity in feet per second and g acceleration due to gravity in feet per
second squared.
For purposes of this example, it was assumed that H at the monitoring point
would be converted to an equivalent amount of pressure head P/w at the
individual well head. This in fact would not be the case, since, as can be
seen in Figure lOB, the total head available in a flowing pipe decreases in
the downstream direction due to headlosses (hf) caused by friction. The
example given in Figure 1 0 is simplistic but the point is that less energy
will be available as you go downstream in a flowing pipe, thus the maximum
pressure which could be assumed equal to available energy also decreases.
The approach discussed above for approx.i.mating pressure will in all cases
overpredict the pressure at an individual well head. The amount that it
overpredicts will be directly related to headloss (friction loss) through
the various branches of the system and differences in topographic relief.
The age of the pipe may significantly affect head loss resulting in even
greater overpredict.ion of pressure at the well head. The magnitude of
overprediction may also be impacted by pressure increases which occur
across branch points in the system. These pressure increases are functions
of flow distribution. Headloss is a function of flow velocity in each
pipe, which is directly related to the distribution of flow through the
system.
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( A) ENERGY DIAGRAM ASSUMING AVAILABLE
Woodward.Ctyde Consultants.
tNOIVIDUAL
WELL HEAD
HEAD AT MANIFOLD CONVERTED TO
PRESSURE HEAD AT WELL
AVA LAbL H AU b iw N MANIFOLD
AND WELL
LEGEND
V = FLOW VELOCITY
P PRESSURE IN PIPE
hf = FRICTION HEAD LOSS
w = UNIT WEIGHT OF
FLOWING FLUID
2 = DISTANCE ABOVE
DATUM
g ACCELERATION
DUE TO GRAVITY
NOTE:
p v 2
1. TYPICALLY • j
ASSUMED AND AC1 JAL ENERGY
DIAGRAM FOR WELL HEAD PRESSURE
USING MANIFOLD PRESSURE
( B) ENERGY DIAGRAM SHOWING LOSS OF
INDIVIDUAL
WELL HEAD
FIG. 10
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In most cases, the portion of total head made up by kinetic energy (V 2 /2g)
would be relatively small. Typically, velocities in injection systems
range from about 3 to 10 feet per second (ft/sec). At a flow velocity of
10 ft/sec, the portion of total head made up of kinetic energy would be
approximately 1.55 feet or about 0.67 psi.
The portion of total head lost to friction in many cases is relatively
small. In the manifold monitoring example, Section 3.3.2, previously
discussed, velocity was about 7.8 ft/sec, with a friction loss of about
62.6 feet or 27.1 psi. The velocity of 7.8 ft/sec would generally be
considered as slightly above average, thus the headloss over the 2000 feet
of pipe might also be considered slightly above average. If the maximum
flow path were about 2 miles, the headloss would be about 143 psi.
Assuming the pressure gauge on the manifold was indicating a typical
pressure of about 3500 psi, the maximum percent difference between the
manifold gauge and the well head would be 4 percent. Although the pressure
cannot be estimated directly, its maximum value based on the manifold
pressure, may only be an overprediction by as much as 7 or 8 percent. The
higher the system pressure, at the same headloss, the smaller the percent
of overprediction. At a system pressure of 5000 psi, the estimated well
head pressure based on a manifold pressure measurement would only be about
3 percent for a headloss of 143 psi.
3.4 WELL INJECTIVITY
The injectivity of the well is the ability of the well to discharge
injection fluid to the surrounding formation. Typically, if a well has
high in)ectivity, the injection formation readily accepts injection
fluids. Based on this definition of injectivity, the elements of manifold
and individual well monitoring which are relevant in its determination
include injection pressure and flow rate. The nature of the injected fluid
may also have an impact on injectivity; however, for purposes of this
document, water is assumed to be the injection fluid.
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3.4.1 Individual Well Monitoring
Measurement of pressure and flow at the well head should be relatively good
indicators of well injectivity. The adequacy of these measurements in
determining well injectivity is related to the accuracy of the pressure and
flow meters. Accurate measurement of flow at the well head is the most
important input to estimating changes in injectivity. Overall injectivity
may be adequately determined using individual well head monitoring.
3.4.2 Manifold Monitoring
The use of pressure and flow data from manifold monitoring systems would
appear not to be viable on an individual well basis. These data would be
viable for use in estimating overall field injectivity but of only marginal
value in assessing an individual well.
The major problem with manifold monitoring as it relates to injectivity is
that the injection rate to individual wells is not known with any degree of
certainty. Since injectivity is .relatively sensitive to injection rate,
the inability to measure or estimate flow to individual wells makes
determination of injectivity virtually impossible accept on a field wide
basis.
Additionally, since flow to individual wells is not accurately known, the
possibility exists that total field injectivity estimates are based on less
than all of the wells in the fields. For example, if one well in a field
with four is plugged, the injectivity may appear relatively small but in
fact it could be substantially larger.
The injectivity of a four well system operating with one well plugged would
appear to have only 75 percent of the actual field injectivity. This would
occur due to the added flow into each of the three unplugged wells. The
assumed flow into each well would be on 75 percent of actual, thus
—17—
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injectivity based on this flow and increased pressure would indicate lower
injectivity.
The use of manifold monitoring would provide similar information on a
project/field basis but little would be known about individual well
operation. This is due to the inability to estimate with any degree of
accuracy the flow and pressure to individual wells. The injectivity of an
individual well may be estimated by shutting off flow to all but one well
and measuring flow and pressure with the manifold monitoring system.
3.5 COMPATIBILITY OF INJECTION 1UIDS WITH TUBULAR GOODS AND INJECTION
FORMATION
The compatibility of the injection fluid with tubular goods and the injec-
tiort formation is defined to mean the chemical and physical reaction of
each to one another. chemical compatibility is more specifically defined
as the reaction potential between injected flui4s and the tubular goods of
the well or the injection formation. The physical compatibility of the
injection fluid is further defined as the erosion potential (physical
decomposition) with regard to tubular goods of the well, and the potential
plugging properties with regard to the injection formation.
3.5.1 Individual Well Monitoring
Individual well monitoring appears to be adequate in determining the
potential chemical and physical compatibility of injection fluids with the
tubular goods of the well and the injection formation. The chemical
compatibility of injected fluid would have to be evaluated based on
analysis of samples taken of the injection fluid. The location of the
sampling point should have little impact on the chemical analysis since no
change in the injection fluid is anticipated as it is pumped through the
system. If the injected fluids react in such a way with formation material
so as to reduce injectivity of the well, the ability to detect such a
—18—
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change is based on the accuracy of the flow and pressure metering
devices. The same holds true with regard to physical compatibility of
injection fluids with the formation. If plugging due to suspended material
occurs, the detectability is related to the accuracy of the flow and
pressure metering devices and the extent of the problem.
3.5.2 Manifold Monitoring
The primary difference between the manifold monitoring and individual well
monitoring as it relates to determining the compatibility of injection
fluid with tubular goods of the well or the injection formation, is the
ability to detect changes in pressure and flow rate to each well. If the
injected fluid reacts similarly in each well, the manifold monitoring
system should be adequate. Howeve , if problems occur on an individual
well basis, detection may be difficult for the reasons discussed
previously. The location of a sampling point should have no effect on
chemical analysis for determining compatibility.
4.0 VALIDITY AND SENSITIVITY OF MANIFOLD DATA
4.1 INTRODUCTION
The following section discusses the limitations of size and extent of the
manifold on the validity and sensitivity of data obtained by manifold
monitoring particularly in light of field size, configuration and
topographical variation.
The size of the manifold is defined as the inside dimensions of the
manifold pipe. Extent of the manifold is defined as overall length of the
manifold system from the injection pump to the various injection well
heads. Field size refers to the overall dimensions of the recoverable oil
bearing formation. The configuration of the field refers to the general
three dimensional shape of the oil bearing formation and topographical
—19—
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variation refers to the elevation of land surface above the oil bearing
formation.
The validity and sensitivity of data obtained from manifold monitoring is
evaluated based on its representation of conditions at any individual well
head which, if known, can be, by using simple hydraulic techniques, used to
estimate conditions at the injection formation.
4.2 FL Q DATA
4.2.1 Validity
Flow data obtained from a manifold monitoring system is valid as an
indicator of injection rates or volumes on a project/field basis. They
would not in any way be an indicator of the proportion of the total project
flow that may be going to any individual well. The size and extent of the
manifold should not impact the operation of the selected flow meter as an
indicator of total field injection rate. The larger the manifold,
generally, the larger the injection rates. The extent of the manifold
indicates the general size of the field but should have no impact on the
validity of flow measurement. Field configuration and topography of the
ground surface of the field would not impact validity of flow measurement.
4.2.2 Sensitivity
The sensitivity of the flow data obtained from a manifold monitoring system
would only be affected by the overall project injection rate. The larger
the injection rate, the larger the meter capacity. As meter capacity
increases, the sensitivity of the meter to small changes in flow is dimin-
ished. The sensitivity of the meter, in general, would not be reduced by
manifold size, extent, field size, configuration and topographical
variation unless it was related to injection fluid flow rate.
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4.3 INJECTION PRESSURE
4.3.1 Validity
The pressure measured at the manifold monitoring point is not valid as
injection pressure at the individual well heads. As discussed previously,
pressure at the manifold may be relatively close to the actual pressure at
the injection well head but the difference is a function of headloss which
in turn is a function of flow distribution within the system. This differ-
ence may also be a function of elevation difference between the manifold
monitoring point and various injection wells. Since elevation differences
would remain constant, they can easily be accounted for and they should not
limit manifold size or extent.
The manifold extent significantly impacts the approximate validity of the
pressure measured at the manifold as an indicator of injection pressure.
The longer the manifold system, the greater the total head].oss through the
system. Since headloss is a function of flow distribution (velocity in
individual pipes) and flow distribution is not known with any degree of
accuracy throughout the system, headlosses are also not known. The
headloss from the manifold to the various injection wells increases with
manifold extent and age of pipes making the potential greater for
substantial differences in pressure between these two points.
4.3.2 sensitivity
The size of the manifold does not impact the sensitivity of the pressure
measurement made there. The extent of the manifold generally has no impact
on sen8itivity of pressure measurements. If the manifold system were to
become large enough to require a significantly higher range pressure gauge
then some sensitivity may be lost. This situation is highly unlikely due
to additional pumping cost. The piping system would be designed to
minimize pumping costs.
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Under most normal operating conditions, the impact of field size, configur-
ation and topographical variation would not impact manifold size or extent
limitation as they relate to validity and sensitivity of pressure data
measured on the manifold.
4.4 NATURE OF INJECTED FLUID
Since the nature of injected fluids is not expected to change from point to
point in the system, the impact of manifold size and extent on validity and
sensitivity of data obtained at the manifold is expected to be insignif i—
cant.
5.0 EVALUATION CRITERIA
5.1 INTRODUCTION
The following section provides evaluation criteria for use by EPA personnel
in evaluating whether manifold monitoring programs are comparable to an
individual injection well monitoring program for the same field. The
evaluation criteria presented in this section are based on the discussions
in Sections 3 and 4 of this report which are summarized below:
(1) Manifold monitoring is of limited use in detecting leaks in the
tubular goods of the well. There are several reasons for this.
First, leaks cannot be located since this method of monitoring
provides data only on the system as a whole and not the individual
wells. Secondly, the degree of accuracy of flow measurements allows
for detection of only large leaks. Third, pressure changes would have
to be great enough to detect. Other conditions of well plugging and
pipe breakage also make manifold monitoring of limited viability in
detecting anything but large leaks. The individual well monitoring
system would potentially have better capabilities of detecting smaller
leaks manifested through pressure and flow rate changes.
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In summary, manifold monitoring systems would generally be less sensi-
tive to pressure and flow changes than individual well monitoring
systems. As a result, this level of sensitivity would make manifold
monitoring less likely to detect leaks identified by individual well
monitoring on the same systems but potentially able to detect large
leaks. It is important to note that the size of the leak with respect
to the specific system is a key element in evaluating whether either
an individual well or manifold monitoring system is capable of
detecting it through pressure and flow changes.
(2) Manifold monitoring is of limited use in determining individual well
injection pressures. The pressure on the manifold provides no direct
means of estimating pressure at the individual well heads. A
determination must be made, to base the pressure for compliance
purposes on the pressure at the individual well or to base the
pressure on the overall field limit, measured at the manifold
monitoring point. The operating and maximum injection pressures at
the manifold monitoring system could be set by considering all the
headloss factors in the manifold system.
(3) Well injectivity for a manifold monitoring system cannot be estimated
with any degree of accuracy, but can only provide an estimate of over-
all field injectivity. A manifold system cannot measure injection
rate to individual wells, and the possibility exists that total field
injectivity may be based on less than all the wells in the field.
However, injectivity tests may be performed on individual wells in a
manifold system if wells can be shut in separately.
(4) Detection of compatibility problems between the injection fluid and
the tubular goods and/or the injection formation may be difficult
because of the ability to detect changes in pressure and flow rate to
each well. This is especially true if problems do not occur similarly
in each well. However, the location of sampling points to determine
—23—
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the compatibility of injection fluid with tubular goods and the
injection formation is not critical in a manifold monitoring system.
(5) Plow data from a manifold monitoring system are valid as indications
of injection rates or volumes on a project/field basis. The data
collected will not be an indicator of the proportion of the total
project flow going to any individual well. Size, extent, field
configuration and topography would not affect the validity of flow
measurements.
(6) The sensitivity of the flow data obtained from a manifold monitoring
system is affected by the overall project injection rate (flow). As
meter capacity increases, sensitivity of the meter to small changes in
flow decreases.
The sensitivity of the meter, in general, would not be reduced by
manifold size, length of the manifold system, field size, the shape of
the oil formation or topographical variation.
(7) Injection pressure measured at the manifold monitoring point is not
accurate as an indicator of injection pressure at the individual well
heads. Pressure at the well head is a function of injection pump head
minus headloss through the system, and the longer the manifold, the
greater the total headloss through the system. Therefore, there could
be differences in pressure between the manifold monitoring point and
the individual well heads. However, this difference compared with a
typical injection system pressure would be small.
(8) The sensitivity of pressure measurement is not affected by the size or
length of the manifold. Sensitivity of a pressure gauge would be
reduced if a higher pressure were required because of system injection
requirements.
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(9) The sensitivity and validity of data on the nature of in ected fluids
are not significantly affected by manifold size and length.
For purposes of this document, a comparable manifold monitoring system is
one which has the same degree of adequacy as the alternative individual
well monitoring system. The question of adequacy is beyond the scope of
this document. If the individual well monitoring systems, based on current
technology and economics, have been considered and deemed inadequate for
determining various parameters, a comparable manifold system would also
have the same inadequacy. For example, if an individual well monitoring
system had an accuracy of O.S percent of the rated flow but would not be
adequate in determining a leak under normal operating conditions, then a
manifold system with the same accuracy would also be inadequate but poten-
tially comparable. Normal operating condition assumes regular operating
personnel following routine procedures. If an individual system is capable
of detecting leaks with additional personnel and alternate procedures, the
operating condition could not be considered normal and the question of
whether two systems are comparable could not be made on this basis.
5.2 APPROACH TO CRITERIA DEVELOPM JT
The development of criteria for evaluating proposed programs requires that
magnitudes be assigned to various measured parameters by the EPA in order
to clearly define adequacy. Also, the definition of minimum requirements
for an individual system are critical in determining adequacy of that sys-
tem to perform a particular monitoring operation at a specific level of
detail. If individual systems with low accuracy levels are allowed that
are inadequate in determining even relatively large leaks, then the
requirements for a comparable manifold system will be significantly less
stringent.
The following discussion of evaluative criteria provides a qualitative, and
to the degree possible, quantitative approach for examining individual well
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meter adequacy arid their comparison with proposed manifold monitoring
systems.
The initial step in examining a manifold monitoring system would be to
define the minimum acceptable program for an individual monitoring sys-
tem. Once the minimum acceptable program for the individual system has
been clearly defined, the adequacy of that system to provide necessary data
for determining leaks, for instance, can be evaluated. Based on this
evaluation, the proposed manifold system can be examined. Listed below is
the evaluative procedure developed as part of this study for individual and
manifold monitoring systems.
The minimum requirements for individual well metering systems would be
based on criteria established by the regulating agency. The adequacy of
the individual well metering system would be evaluated based on the minimum
requirements as follows:
(1) Leaks in Tubular Goods of the Well . The flow monitoring device should
be of the required accuracy to detect a specific lower limit of incre-
mental changes in flow. The lower limit of incremental changes in
flow would be specified by the regulatory agency.
(2) Compliance with Injection Pressure . The pressure meter should be of
the required pressure range to measure anticipated pressure. The
accuracy of the gauge should be such that pressure at the well head
could not exceed regulatory agency limitation by a specified amount
without detection.
(3) Injectivity of the Well . The minimum requirement for pressure and
flow metering as a means of determining well injectivity would be
based on regulatory agency guidelines. The metering devices selected
and their accuracies should be within these minimum requirements.
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Woodward.Clyde Consultants
(4) Compatibility of Injection Fluid With Tubular Goods and the Injection
Formation . The sampling point may be anywhere in the system; no
anticipated impact on results is expected.
The comparison of a proposed manifold monitoring system with an individual
well monitoring system would be as follows:
(1) Leaks in Tubular Goods of the Well(s) . Based on the requirements
established for an individual well described previously, a flow meter
selected to monitor a manifold would have to have the accuracy to
detect changes in flow of the same magnitude. If the metering device
were able to detect flow rate changes of the same magnitude, then it
would be considered comparable.
(2) Compliance with Injection Pressure Limitations . The manifold pressure
monitoring system cannot be used to estimate well head injection
pressure since information on flow distribution through the system is
not available. However, if compliance is based on a pressure head at
an individual well assumed equal to the total available head at the
manifold monitoring point, the actual well head pressure will be
less. If the injection pressure limitations are for the overall field
rather than discrete injection points, the manifold system can be
utilized; however, if the injection pressure limitations are for
discrete points, the manifold system cannot, with any degree of
accuracy, determine individual well injection pressures.
(3) Injectivity of the Well . The manifold system will not provide any
meaningful data on the injectivity of a well, only the apparent
injectivity of the field.
(4) Compatibility of Injection Fluid with Tubular Goods and the Injection
Formation . As discussed in the text, the location of the sampling
point for individual well or manifold type systems would have no
impact on determining compatibility. The systems should be the same
in either case.
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WoodwardClyde Consultants
REFERENCES
Geraghty & Miller, Inc., 1982, Guidance Document on Mechanical Integrity
Testing of Injection Wells , prepared for U.S. Environmental Protection
Agency, April 30.
Hall, H.N., 1963, “How to Analyze Waterflood Injection Well Performance”,
World Oil , October.
Hayward, Alan T.J., 1970, Flowmeters , John Wiley & Sons, New York, N.Y.
Hearn, Charles L., 1983, “Method Analyzes Injection Well Pressure and Rate
Data”, Oil & Gas Journal , April 18.
Hecker, George F., Nystom, James B., and Qureshi, Nazir A., 1977, “Effect
of Branch Spacing on Losses in Dividing Plow”, ASCE, Journal of the
Hydraulics Division , Vol. 103, No. Hy3, March.
Hudson, H.E., Uhier, R.B. and Bailey, Robert W., 1979, “Dividing Flow
Manifolds and Square—Edged Laterals”, ASCE, Journal of the
Environmental Engineering Division , Vol. 105, No. ER4, August.
King, Horace W. and Brater, Ernest F., 1963, Handbook of Hydraulics , 5th
Ed. McGraw—Hill Company, New York, N.Y.
Li, Yu Tek, 1973, “Head Losses in T-Junctions and Manifolds”, Water Power ,
July.
McNown, John S., 1954, “Mechanics of Manifold Flow”, Transactions ASCE ,
Vol. 119, Paper 2714.
Olsond, Reuben M., 1973, Essentials of Engineering Fluid Mechanics , Intext
Educational Publishers, New York, N.Y.
Patton, Charles C., 1977, “Practical Considerations in the Design of Oil
Field Injection Systems”, Material Performance , Vol. 16, November.
Rhone, Thomas J., 1973, “General Considerations of Flow in Branching
Conduits”, Hydraulic Engineering and the Environment , proceeding of
the 21st Annual Hydraulics Division Speciality Conference, August 15—
17.
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Woodward. Clyde Consultants
Ruus, Eugen, 1973, ‘Flow Through Trifurcations and Manifolds 0 , Hydraulic
Engineering and the Environment , proceeding of the 21st Annual
Hydraulics Division Speciality Conference, August 15—17.
Vernard, John K., 1961, Elementary Fluid Mechanics , 4th Ed., John Wiley &
Sons, Inc., New York, N.Y.
Villemonte, James R., 1973, ‘Some Basic Concepts of Flow in Branching
Conduits”, Hydraulic Engineering and the Environment , proceeding of
the 21st Annual Hydraulics Division Speciality Conference, August 15—
17.
Williamson, James V., and Rhone, Thomas J., 1973, “Dividing Flow in
Branches and Wyes”, ASCE, Journal of the Hydraulics Division , Vol. 99,
No. Hy5, May.
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APPENDIX A
ADDITIONAL FLOW MEASURING DEVICES
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A-i INTRODUCTION
In addition to the more common differential and rotating mechanical type
meters, numerous variation to these meters as well as completely different
meters have been developed to accomodate special application. In some
cases, existing meters were modified to reduce headloss, in others, modif i-
cations addressed special problems associated with the fluid being measured
such as suspended sediment. The following section describes and discusses
an additional assor ent of pressure differential and rotating mechanical
meters which potentially could find application in all enhanced recovery
injection systems.
A-2 PRESSURE DIFFERENTIAL MtTERS
Th three basic pressure differential meters (orifice, venturi and nozzle)
have seen many modifications in an effort to improve operating characteris-
tics. The opening of an orifice has in some cases been moved from its
concentric location in a pipe to various positions as shown on Figure A—i-a
and b. These locations allow the passage of solids through the meter and
prevent the accumulation of solids upstream of the meter which could affect
performance.
The headlosses across the orifice type meter are generally recognized as
the highest of the pressure differential type meters with the smallest
installation space requirement. The venturi type meter has the smallest
headloss with the largest installation space requirement. To reduce the
required installation space of the venturi, the venturi nozzle was devel-
oped (Figure A—2). This meter requires less installation space than the
standard venturi; however, the nozzle type entrance results in higher meter
headloss.
A—i
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Modifications to the standard venturi have been made to reduce its already
low headloss characteristics. Two devices include the Dali tube and the
Universal venturi. The devices are shown on Figure A-3. Other pressure
differential devices which are modifications to the more common devices
such as the orifice and venturi, are the Dali orifice and the Epif 10
(Figure A—4).
A-3 ROTATING MECHANICAL METERS
The number of rotating mechanical meters, other than the positive displace-
ment and turbine type, is considerable. A number of these meters are
discussed below with regard to configuration and operation.
The constrained—vortex meter is sometimes referred to as a vortex meter.
The vortex meter consists of a large, freely spinning rotor mounted such
that its axis is perpendicular to the flow path, which is eccentrically
placed in a bulge in the pipe. A typical schematic for vortex type meter
is shown on Figure A—5a. The vortex meter is generally cheaper but less
accurate than the positive displacement and turbine meters.
The Hoverflo is described as a bearingless type transmitter. The Hoverflo
is like a double rotameter with two floats joined together by a rigid shaft
and each taking half the main flow. When flow is passing, the rotor takes
up a central position which is one of stable equilibrium and thus it floats
without metal-to-metal contact. A magnetic pick-up provides a direct dig-
ital output. A schematic of the Hoverflo meter is given on Figure -5b.
Another type of rotating flow meter is the angled propeller meter. This
type of meter is inserted into the flow section with a propeller of suff i-
cient size to be affected by practically the whole flow passing. The
bearings of such a meter are located outside the flow stream making them
less likely to be susceptible to damage. A typical schematic of an angled
propeller meter is shown on Figure A—6.
A- 2
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ConsuftaMs —
TAP POSITION
TAP POSITION
VARIATION OF
ORIFICE TYPE METER
(a) CHORD ORIFICE
(b) ECCENTRIC ORIFICE
4 ’ : ’
FIG. A-I
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URE
NOZZLE TYPE
ENTRANCE
VENTURI NOZZLE
FLOW
FIG. A-2
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Woodward.c*yde Consultants —
PRESS
R TAPPI NGS
FLOW
DRAIN PLUGS
(a) ‘DALL’ TUBE
(b) ‘UNIVERSAL’ VENTURI
LOW HEADLOSS
‘RESSURE DIFFERENTIAL FLOW
METERS
PRESSURE TAPPINGS
FIG. 4-3
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Woodward.csyde Consultants —
‘•/‘/// ‘I
,THROAT
TAPPING
\ \\\\\ ‘
U P STR E AM
TAPPING
(a) ‘DALL’ ORIFICE
PRESSURE TAPPINGS
(b) THE ‘EPIFLO’
LOW HEADLOSS
ORIFICE TYPE FLOW METERS
FLOW
FLOW
a-
FIG. 4-4
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t_I______________j At - - -A - a -
(o) VORTEX METER
MAGNET-.. /PICKUP
rzu _ -h V/i____
3F v _ ___(
(b) HOVERFLO METER
ROTATING MECHANICAL
FLOW METERS
FLOW
FIG. A-5
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I Woodwatd.clyde Consultants —
ATION OUTPUT SIGN4L
ANGLED PROPELLER
TYPE FLOWMETER
FIG. 4-6
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