Surface Facilities for Waterflooding and Saltwater Disposal.

34
Chapter 15 Surface Facilities for Waterflooding and Saltwater Disposal K.E. Arnold, Paragon Engineering Services* Introduction In producing operations it is often necessary to handle brine that is produced with the crude oil. This brine must be separated from the crude oil and disposed of in a man- ner that does not violate environmental criteria. In off- shore areas the governing regulatory body specifies a maximum hydrocarbon content in water that it will allow to be discharged overboard. Currently this ranges from 7 to 72 mg/L depending on the specific location. In most onshore locations the water cannot be disposed of on the surface because of possible salt contamination and it must be injected into an acceptable disposal formation or disposed of by evaporation. On the other hand, it is often desimble to inject water into the producing formation to maintain reservoir pressure or increase recovery through watetllooding. Produced water that is properly treated to remove hydrocarbons and solids can be used for this pur- pose. In addition, supplemental sources of water from other formations or from surface sources could be used for watefflooding The purpose of this chapter is to discuss the equipment and design criteria that are employed in common systems for either waterflooding or for saltwater disposal. In both cases the design engineer may be concerned with design- ing piping systems, selecting pumps, separating solids from water, treating hydrocarbons from water, removing dissolved gases and solids from water, treating hydrocar- bons from solids, and overall project management. Piping System Design In any waterflood or disposal system, it is necessary to gather the water from one or more sources for treatment and then to distribute it to one or more points for injec- tion or disposal. This section discusses criteria for select- ing pipe diameter, pipe materials, and wall thickness, as well as general design considerations for cross-country piping systems. ‘Authors oftheorigmal chapter on thus topic inthe1962 edition were W F.Ellison and R.H. Lasater. Pipe Diameter The choice of pipe diameter depends on the pressure drop available, or on a range of acceptable velocities for fluid flow in the pipe. Pressure at a Point. The pressure at any point in a system can be determined from Bernoulli’s theorem, if the pressure at any other point is known. This theorem, which is derived from conservation of energy, is given by z, +P1+(“1)2=22+)2+L!e+zfl, . ..(I) PI 2g P2 2g where Z = elevation above a datum, p = pressure, p = density, v = velocity, g = gravitational constant, and Zj = head loss due to friction between Points 1 and 2. Darcy demonstrated that head loss was given by flV2 zfl=- 2gdi . . . . . . . . . . . . . . . . . . . . . . . . where f = friction factor, L = length, and di = pipe ID. The friction factor is, in turn, a function of the non- dimensional Reynold’s number, given by h&=@ . . . . . . . . . . .(3) FL

description

Chapter 15Surface Facilities for Waterflooding and Saltwater DisposalK.E. Arnold,Paragon Engineering Services*IntroductionIn producing operations it is often necessary to handle brine that is produced with the crude oil. This brine must be separated from the crude oil and disposed of in a manner that does not violate environmental criteria. In offshore areas the governing regulatory body specifies a maximum hydrocarbon content in water that it will allow to be discharged overboard. Curren

Transcript of Surface Facilities for Waterflooding and Saltwater Disposal.

Page 1: Surface Facilities for Waterflooding and Saltwater Disposal.

Chapter 15

Surface Facilities for Waterflooding and Saltwater Disposal K.E. Arnold, Paragon Engineering Services*

FL

Introduction In producing operations it is often necessary to handle brine that is produced with the crude oil. This brine must be separated from the crude oil and disposed of in a man- ner that does not violate environmental criteria. In off- shore areas the governing regulatory body specifies a maximum hydrocarbon content in water that it will allow to be discharged overboard. Currently this ranges from 7 to 72 mg/L depending on the specific location. In most onshore locations the water cannot be disposed of on the surface because of possible salt contamination and it must be injected into an acceptable disposal formation or disposed of by evaporation. On the other hand, it is often desimble to inject water into the producing formation to maintain reservoir pressure or increase recovery through watetllooding. Produced water that is properly treated to remove hydrocarbons and solids can be used for this pur- pose. In addition, supplemental sources of water from other formations or from surface sources could be used for watefflooding

The purpose of this chapter is to discuss the equipment and design criteria that are employed in common systems for either waterflooding or for saltwater disposal. In both cases the design engineer may be concerned with design- ing piping systems, selecting pumps, separating solids from water, treating hydrocarbons from water, removing dissolved gases and solids from water, treating hydrocar- bons from solids, and overall project management.

Piping System Design In any waterflood or disposal system, it is necessary to gather the water from one or more sources for treatment and then to distribute it to one or more points for injec- tion or disposal. This section discusses criteria for select- ing pipe diameter, pipe materials, and wall thickness, as well as general design considerations for cross-country piping systems.

‘Authors of theorigmal chapter on thus topic in the 1962 edition were W F. Ellison and R.H. Lasater.

Pipe Diameter

The choice of pipe diameter depends on the pressure drop available, or on a range of acceptable velocities for fluid flow in the pipe.

Pressure at a Point. The pressure at any point in a system can be determined from Bernoulli’s theorem, if the pressure at any other point is known. This theorem, which is derived from conservation of energy, is given

by

z, +P1+(“1)2=22+)2+L!e+zfl, . ..(I)

PI 2g P2 2g

where Z = elevation above a datum, p = pressure, p = density, v = velocity, g = gravitational constant, and

Zj = head loss due to friction between Points 1 and 2.

Darcy demonstrated that head loss was given by

flV2 zfl=- 2gdi ’

. . . . . . . . . . . . . . . . . . . . . . . .

where f = friction factor, L = length, and

di = pipe ID.

The friction factor is, in turn, a function of the non- dimensional Reynold’s number, given by

h&=@ . . . . . . . . . . .(3)

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15-2 PETROLEUM ENGINEERING HANDBOOK

where NRe is the Reynold’s number and p is the viscosi- ty. The relationship between Reynold’s number and the friction factor is given in the classical Moody diagram (Fig. 15.1).

Pressure Drop in Liquid Lines. The pressure drop for liquid lines can be derived from Eq. 1 as

4J= 0.0000115flq~)2y~L

(di)5 , . . . . . . (4)

where Ap = pressure drop, psi, qL = liquid flow rate, B/D, ye = specific gravity of liquid relative to water,

L = length of line, ft, and d; = pipe ID, in.

This relationship is shown graphically in Fig. 15.2. For liquid flow in pipelines, a friction factor of 0.02 is

sometimes used for preliminary calculations. In deter- mining the actual friction factor from Fig. 15.1, it is sometimes convenient to use either of the following equations.

NRe =7,734 TLdiv

. . . . . . (5)

or CL

NRe=92.1 YL4L -----$-, . . . . . . . . . . . . . . . . (6)

where v is velocity, ftis, and p is viscosity, cp. The roughness, 6, to use in determining which

relative-roughness, t/d, curve governs in Fig. 15.1 depends on the age of the pipe and the material that lines its inside surface. Cast-iron pipe could be expected to be rougher than bare-steel pipe and bare-steel pipe rougher than plastic-lined steel pipe. Roughness factors for new pipe are given in Table 15.1. These should be increased by a factor of two to four to account for corrosion or in- crustation effects that could occur with age.

In the past, the empirical Hazen-Williams’ equation has been used by some engineers for flow of water through pipelines. With the advent of computers and programmable calculators, these empirical equations are no longer recommended. However, for completeness, the Hazen-Williams equation is given as

zj =0.015 (4L) ‘.*5L

(di)4.87(CHW)‘.85 ’ ’ ’ ’ ’ ’ ’ ‘. ‘.

where ZJ = friction head loss, ft of liquid, qL = liquid flow rate, B/D,

L = length of line, ft, di = pipe ID, in., and

CHW = constant with a value of 80 to 140, depending on the inside pipe material and its age.

(7)

In determining the length to be used in either Eq. 4 or 7, it is necessary to include an allowance for valves, ells, tees, reducers, and entrance and exit losses from vessels. The most common way of accounting for these pressure losses is to include a certain additional length of pipe to the actual length of pipe in the value used for L. Table 15.2 shows the length of pipe that should be added for various valves and fittings.

Velocity in Liquid Lines. Although it is necessary that a selected pipe diameter ensures that the pressure drop is not excessive, in many cases the velocity in the line, and not the pressure drop, will determine the pipe diameter. In most of the short liquid lines within the plant, there will be more than sufficient pressure available to transport the liquid from one piece of equipment to another. However, if the entire pressure drop were taken in the piping, and only a marginal pressure drop were taken across a liquid-control valve, the velocities in the pipe would be high enough to cause noise, erosion of products of corrosion, or water-hammer problems. For this reason a maximum liquid flow velocity of 15 ftis usually is recommended.

Consideration should also be given to a minimum velocity necessary to prevent solids buildup in the bot- tom of the pipe. Experiments have shown that when the liquid velocity falls below a certain value, any solids present will settle in a horizontal bed until an equilibrium velocity is reached over the bed. At this velocity, erosion of the solid particles on the surface of the bed is exactly balanced by the deposition of additional particles. It can be shown that, for situations likely to be encountered in oilfield pipelines, a velocity of between 2 and 4 ftis is re- quired to keep from building up such a bed. For this reason a minimum velocity of 3 ft/s is usually preferred for any liquid piping likely to contain solids.

The following equation has proved useful in calculating velocities.

v=o.o124L (di)2 . . . . . . . . . . . . . (8)

This equation is shown graphically in Fig. 15.3.

Choosing Pipe Diameters in Liquid Lines. The choice of a pipe diameter for a liquid line thus becomes one of choosing a diameter large enough for the pressure available while attempting to keep the velocity between 3 and 15 ft/s. On short lines within a plant, it is usually quicker to choose a diameter based on velocity con- siderations and then check for pressure drop. On longer lines, or on lines within a plant that flow between at- mospheric tanks (low available pressure), it is usually desirable to choose a diameter based on pressure-drop considerations first and then to check velocity.

On lines that experience large variations in elevation, it is desirable to employ Bernoulli’s theorum (Eq. 1) at all high points to ensure that there is sufficient positive pressure so that a vacuum is not created. Although it is possible to operate a line with a high-point vacuum, rely- ing on a syphon effect may make it difficult to restart a line if the syphon ever loses its liquid seal. In addition, at any point where a vacuum exists, there is a very real feasibility of drawing oxygen into the system with resul- tant corrosion and bacteria problems.

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SURFACE FACILITIES FOR WATERFLOODING & SALTWATER DISPOSAL 15-3

.

:

,

6 tb+.*.t*. t

Fig. l&l-Friction factor chart.

Fig. 15.2-Pressure drop in liquid lines.

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15-4 PETROLEUM ENGINEERING HANDBOOK

TABLE 15.1-ABSOLUTE PIPE ROUGHNESS (IN.), NEW PIPE

Unlined concrete Cast iron Galvanized iron Carbon steel Fiberglas epoxy Drawn tubing

0.0 1 to 0.1 0.01

0.006 0.0018 0.0003 0.0001

TABLE 15.2-EQUIVALENT LENGTH OF 100% OPENING VALVES AND FITTINGS (FT)

Weld Thread

Nominal Short Long Pipe Size Globe Valve or 450 Radius Radius Hard Soft

(in.) Ball Check Valve Angle Valve Swing Check Valve Plug Cock Gate or Ball Valve Eli Eli Ell T T -- 1% 2 2% 3 4 6 8

IO 12 14 16

:: 22 24

fi 42 48 54 60

55 26 70 33 80 40 100 50 130 65 200 100 260 125 330 160 400 190 450 210 500 240 550 280 650 300 666 335 750 370 - -

- -

13 7 17 14 20 11 25 17 32 30 48 70 64 120 80 170 95 170 105 80 120 145 140 160 155 210 170 225 185 254 - 312 - -

- -

4 6 7 9 10 11 12 14 15 16 21 25 30 35 40 45

1-2 3-5 2-3 8-9 2-3 2-3 4-5 3-4 10-11 3-4 2 5 3 12 3 2 6 4 14 4 3 7 5 19 5 4 11 8 28 8 6 15 9 37 9 7 18 12 47 12 9 22 14 55 14 10 26 16 62 16 11 29 18 72 18 12 33 20 82 20 14 36 23 90 23 15 40 25 100 25 16 44 27 110 27 21 55 40 140 40 25 66 47 170 47 30 77 55 200 55 35 88 65 220 65 40 99 70 250 70 45 110 80 260 80

900 Miter Bends

Enlargement Contraction

Standard Sudden Reducer Sudden

Equivalent L in Terms of Small d”

Standard Reducer

Two-miter Three-miter Four-miter d/D=% d/D= I/s d/D=3h d/D=% d/D=j/a d/D=,/4 &-,=,,z d/0=3/4 d,D=,,2 d/D=Q

- - - 5 - - - 7 - - - 8 - - - 10 - - - 12 - - - 18 - - - 25 - - - 31 28 21 20 37 32 24 22 42 38 27 24 47 42 30 28 53 46 33 32 60 52 36 34 65 56 39 36 70 70 51 44 84 60 52 - 98 69 64 - 112 81 72 - 126 90 80 - 190 99 92 -

‘d is ID of smaller outlet and D IS ID of larger outlet.

3 4 5 6 8

12 16 20 24 26 30 35 38 42 46

- - - - -

1 1 2 2 3 4 5 7 8 9

10 11 13 14 15

- - - - -

4 1 5 1 6 2 8 2 10 3 14 4 19 5 24 7 28 8 - - - - - - - -

-

- - - - -

-

-

- - -

3 3 4 5

i 12 15 18 20 24 26 30 32 35

-

- - -

2 1 3 1 3 2 4 2 5 3 7 4 9 5 12 6 14 7 16 8 18 9 20 10 23 11 25 12 27 13

- - - - -

-

- - -

1 1 2 2 3 4 5 6 7

- - - -

-

-

- - -

- - - - -

1 2 2 2

- - - - - -

-

- - -

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SURFACE FACILITIES FOR WATERFLOODING & SALTWATER DISPOSAL 15-5

LIQUID FLOW RATE, BARRELS FLUID/DAY

Fig. 15.3-Velocity in liquid lines.

Sometimes, it is not feasible to satisfy minimum velocity criteria during the early stages of a project, where flow velocities are low, without violating pressure drop or maximum velocity criteria at peak flow rates. In such cases, engineering judgment is needed to choose between alternatives such as (1) installing a smaller line initially and either looping the line or installing more pumps at a later date, (2) allowing an equilibrium-solids bed to be deposited initially and relying on it being erod- ed as flow velocities increase, or (3) allowing a velocity greater than 15 ft/s at peak flow rates.

Pressure Drop in Gas Lines. Although this chapter deals primarily with liquid flow, it may be necessary to size gas lines as part of the project. Source water may come from gas-lifted wells, which would require a gas- lift gas-distribution system, produced water may have flash gas associated with its separation and treating equipment, flotation units and gas strippers require gas lines to operate, and fuel, instrument and utility gas un- doubtedly will be required.

Flow in gas lines is considered isothermal. That is, there is sufficient heat transfer to and from the surround- ing air, water, or soil to keep the temperature of the gas in the line from changing as the pressure changes because of friction losses. If we assume steady-state gas flow, an ideal gas (Z = 1 .O), and a constant friction factor over the length of the line, the following equation can be derived.

(~q)‘-(p~)~=2d~ ;&);T6, . . . . . . . . . 1

where p1 = pressure at pipe inlet, psia, p2 = pressure at pipe outlet, psia, qg = flow rate of gas at standard conditions,

MMscf/D,

y&T = specific gravity of the gas at standard condi- tions relative to air, and

T = temperature, “R.

When the Reynold’s number is calculated to determine the friction factor from Fig. 15.1, it is often convenient to use either

qgyg NRe=20,102- .,......., .__...._._.t (10) diwgf

or

NRe = 335 VgfPldiYg

. . . . . . . . . . . . . . . . t . . (11) TpKf

where vgf is the velocity of gas at specific flow condi- tions, ft/s, and pd is the viscosity of gas at specific flow conditions, cp.

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15-6 PETROLEUM ENGINEERING HANDBOOK

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SURFACE FACILITIES FOR WATERFLOODING & SALTWATER DISPOSAL 15-7

The viscosity of the gas at flow conditions can be derived from Fig. 15.4. Where

PI -P2 p<O.l,

PI

Eq. 9 reduces to

12)

It is recommended that either Eq. 9 or 12 be used. However, in the past, two empirical equations were developed that have been used extensively. The Weymouth equation2 is used for lines with high Reynold’s numbers. It assumes that the friction factor is merely a function of pipe diameter. That is, flow is oc- curring in the flat part of the relative roughness curves on the Moody diagram. The Weymouth equation can be written as

(PI)2 -(p2)2 =O.Sl ‘;;;;,;3z. . . . . . . . . 1

(13)

This equation would normally apply to short lines within the plant where gas velocities, and thus Reynold’s numbers, would probably be high. Figs. 15.5 and 15.6 can be used to solve this equation.

For long gas lines, where velocities are likely to be less and the friction factor will depend on both the line size and the flow rate, the Panhandle equation2 has been developed:

0.96 1.96~

(p,)2-(p2)2=0.2 yg g;,,, ) . . . . . . I

(14)

where E is flow efficiency (1 .CKJ for new pipe, 0.92 for average conditions, and 0.85 for unfavorable conditions).

Velocity in Gas Lines. As in liquid lines, there is a velocity consideration in picking a pipe diameter for a gas line. At high velocities, there could be problems with both noise and erosion of the layer of corrosion products on the inside of the pipe. The greater the rate of erosion of these products, the greater the rate of corrosion the line would experience.

From a noise consideration, the velocity in the pipe should be limited to 60 to 80 ft/s at actual flow condition of pressure and temperature Experiments have shown that there is a correlation between velocity and erosion of the products of corrosion, which is given by

vRf=- 2, . . . . . . . . . . . . . . . .

where pg is the density of the gas at actual conditions, lbm/cu ft, and CE is a constant for erosional flow. Eq. 15 can be rewritten as

. . . . . . . . ..I.........

API Recommended Practice 14E” for offshore piping systems proposes using a value of 125 for intermittent service and 100 for continuous service for the constant CE. Recent experimental data indicate a CE as high as 300 may be appropriate for an allowable corrosion rate of 10 mil/yr.

The choice of a value to use between 100 and 300 depends on the judgment of the design engineers as to the corrosivity of the gas and the cost of being overly conservative. Where pressures arc below 1,000 to 1,500 psi, the noise criteria will govern and the erosional criteria can be neglected.

If the gas is saturated to the extent that liquids are like- ly to condense from the vapor phase because of ambient cooling, it is recommended that a minimum velocity of 10 ft/s be maintained. This will sweep the liquid out of the line. At lower velocities, liquid may accumulate at low spots, accelerating corrosion and potentially leading to liquid slugging in the line.

Choosing a pipe Diameter in Gas Lines. As in liquid lines, the choice of pipe diameter will depend on satisfy- ing both the pressure-drop and velocity criteria. For almost all lines within the plant, the velocity criteria will govern, and the pressure drop will probably not even have to be checked. For long gathering or distribution lines the pressure drop available may govern, or a study of pipe diameter and cost vs. compressor horsepower and cost may be necessary.

Materials

Selection of materials for pipe, valves, and fittings for any piping system must take into account the pressure rating of the application, the corrosivity of the fluid, and the location of the line. There is some economic cost over life for each selection and this must be taken into account in determining the types of material to use for a given application.

Asbestos-Cement pipe. Because of its resistance to cor- rosion and low cost, asbestos-cement pipe is recom- mended for use in large-diameter lines on gravity or low- pressure water systems (200-psi maximum working pressure). The joint connection consists of asbestos- cement couplings with rubber rings. The pipe itself is not flexible, but a deflection of 6” can be obtained at the coupling. This proves advantageous in eliminating abrupt bends when it is necessary to lay pipe on horizon- tal or vertical curves. Care must be exercised in the ac- tual laying of the pipe by providing a conditioned ditch for the pipe. Installation guides have been published by the manufacturers of asbestos-cement pipe and are available to the design engineer on request.

Asbestos-cement pipe can be coated internally with plastic or fiberglass to lower the friction factor and to protect against seepage of any crude oil that may be in the water stream. Asbestos-cement has the disadvantage of being more brittle than steel pipe, which could make it susceptible to damage from external loads. In addition, proper bedding and backfill compaction is required to prevent future pipe movement resulting from external loads, which could cause joint leakage.

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15-8 PETROLEUM ENGINEERING HANDBOOK

m 0 r- X

Fig. 15.5-Gas flow based on Weymouth formula.

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SURFACE FACILITIES FOR WATERFLOODING & SALTWATER DISPOSAL 15-9

20,000

l0,000 9,000 8,000 7mo b.000

5.000

two

3.ooa

1.wo 900 Boo 700

600

500

400

300

200

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15-10 PETROLEUM ENGINEERING HANDBOOK

Plastic Pipe. In recent years, there has been a continuing increase in the use of the various types of plastic pipe especially in moderately low-pressure (300 psi), small- diameter (6 in. and lower) water service. Plastic pipe is not susceptible to either internal or external corrosion, it has a low friction factor, and its light weight makes it easy to install. This is a rapidly developing field and there are numerous proprietary brands. However, in general, plastic pipe can be purchased in accordance with the following API specifications: Spec. 5LE for polyethylene line pipe (PE),4 Spec. 5LP for ther- moplastic line pipe (PVC and CPVC),’ and Spec. 5LR for reinforced thermosetting resin line pipe (RTRP). 6

The latter category, which includes fiber-reinforced plastic (FRP) pipe, is the strongest, with PVC next, and PE last. All plastic pipe is sensitive to temperature and must be derated as temperature increases. PE pipe is limited to lOO”F, PVC pipe to 140”F, and RTRP pipe is limited to 150°F unless specific tests are run by the manufacturer.

The pressure rating of plastic pipe also depends on the fluid being handled. PE pipe handling crude oil has 50% of the pressure rating of the same pipe handling water. PVC pipe must be derated to 40 % of its water strength if handling crude oils because of the long-term effect of hydrocarbons on the material. The de&ion of RTRP pipe is specified by the manufacturer.

Because of the superior strength and greater resistance to heat and hydrocarbons, the use of FRP pipe is increas- ing. Pipe is available in diameters to 12 in. and pressure ratings that exceed those in 5LR by a factor of two. However, plastic pipe has the disadvantage of being ex- tremely brittle. This can lead to damage in installation. More important, if the ditch is not prepared correctly in rocky soil, over time as the line settles, rocks can come in contact with the underside of the line and cause a stress concentration and eventual failure. It also has the disadvantage of becoming brittle with time when exposed to direct sunlight.

Cast-Iron Pipe. Satisfactory installations of cast-iron pipe have been made on systems where pressures are more than 200 psi but less than 250 psi. Cast-iron pipe has a high corrosion-resistant quality. This pipe has a higher initial cost than either asbestos-cement or plastic pipe. While it is less susceptible to impact and temperature effects than plastic pipe, it is more brittle than steel pipe. For this reason, it must have flat-faced flanges and care must be exercised to ensure that it is not connected to a valve fitting with a more standard, raised- face flange.

If cast-iron pipe is subjected to a fire and then hit by a stream of cold water, it is susceptible to cracking. For this reason, it is not generally acceptable for services containing hydrocarbons.

Carbon Steel Pipe. The most commonly used material for piping systems is Grade B line pipe (35,000-psi yield) manufactured in accordance with API Spec. 5L for line pipe. ’ Because of its strength, this material can withstand high pressures and is available in diameters to 64 in.

Steel pipe has excellent impact resistance and flexural strength. Unfortunately, it is much more susceptible to both internal and external corrosion, and its installation is more expensive than the lighter plastic pipes.

Where oxygen is excluded from the system, internal corrosion may not be a problem. External corrosion can be reduced by burying and protecting the pipe with a cathodic-protection system. The system could consist of sacrificial zinc or aluminum anodes, which are attached electrically to the pipe at specified intervals. For long pipelines, an impressed-current system may be con- sidered, which would enable the use of fewer anodes.

External corrosion could also be combatted with a coating system. For pipe that is exposed to salt air, a three-coat epoxy-paint system is often specified. Less- elaborate systems are employed in less-severe at- mospheres. Underground or underwater pipe may be protected by a thin-film-epoxy, coal-tar-epoxy, or extruded-plastic system. Thin-film-epoxy systems seem to be more popular lately, because of their greater toughness to potential handling and installation damage.

Most long pipelines are protected both with a coating system and cathodically. The coating system decreases the current demand, while the cathodic-protection system provides protection for any breaks, gaps, or scratches that develop in the coating.

Where internal corrosion is anticipated, carbon steel can be protected in four ways.

1. Cement lining. Individual joints have a s-in. cement-mortar mix applied by a centrifugal spinning procedure. The field joints are protected by an asbestos welding gasket compressed between the joints. Cement- lined pipe is available in sizes from 3 to 24 in. API RP lOE* specifies cement thickness vs. pipe size. The ac- cepted tolerance is f1/j2 in.

2. Co&-kr-epoxy lining. Typically this is a 3/,,-in. lining that is centrifugally spun into the pipe section after a field joint is made. This technique is limited to large- diameter lines.

3. Plastic lining. Various types of epoxies have been installed in steel lines. These can be installed in a small section at a time, or by use of cylindrical devices (pigs), which are run into the line in sections up to 1 mile long. Some success has been reported with plastic lining used to protect pipe against further deterioration, but the necessity of cleaning the pipe wall before applying the plastic coating makes this very difficult. At the present time, manufacturers claim the smallest pipe that can be internally plastic coated is 1 I/ in. nominal.

4. Use of liners. There have been several successful installations of FRP and other liners in steel pipe. The steel provides the strength to resist high pressures and the liner provides corrosion resistance. Other than the high cost of installation, this system has the further drawback in that because of long-term permeability through the liner, the pressure in the annulus between the liner and steel can reach an equilibrium with the line pressure. When the line is depressured for maintenance, this may cause collapse of the liner if the system is not carefully designed. Liners have been installed in pipe from 2- to 30-in. diameter and for distances as long as 0.5 mile in a single pull.

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15-l 1 SURFACE FACILITIES FOR WATERFLOODING & SALTWATER DISPOSAL

TABLE 15.3-DESIGN PROPERTIES AND ALLOWABLE WORKING PRESSURES FOR PIPING’

Namlnal Pipe Welght of Wall ID FIOW Allowable Working Pressures for Temperature~(~F)Not To Exceed

Size Schedule Plfx (OR,

Thtckness d, Area -2OlO (in.] Number (Ibm/ff) (in.) (in.) d: P4 4 100 200 300 400 500 600 700

--ET 'h -- 0651 0.640 -~

0 109 0.622 0.0931 0.00211 2,256 2,256 2,258 2,258- 2,134 -- 1,953 1,863

I'/2

2

3

4

6

8

10

12

14

16

,6

20

24

540

X80 s40 X80 160 XX s40 X80 160 xx 540 X80 160

22 X60 160 xx s40 X80 160 xx s40 xao 160

s"4", X60 xx 160 s40 X60 160 S X 160 10 530 X 10 530 540 IO S X 10 520 x30 10 se0 X

1 131 1474 1.679 2172 2.644 3659 2.718 3832 4.666 6.409 3.653 5022 7.445 9030 7.58 10.25 14.33 18.58 10.79 14.99 22.51 27.54 16.98 28.58 4530 5317 2656 434 724 747 405 54 7 1157 49 6 65 4 ,603 36 7 546 72 1 421 626 828 474 70.6 93 5 52.7 78.6 104.1 63.4 94.6

1255

1.050

1.315

1.900

2.375

3.500

4500

6.625

6825

10750

12750

14.000

16.000

16000

20000

24000

0113 0.824 0.3799

0 154 0742 0 2249

0133 1.049 1.2700 0179 0.957 0.8027 0250 0.815 0.3596 0358 0.599 0.0771 0145 1.810 10.620 0200 1500 7 594 0261 1336 4286 0400 1100 1611 0154 2.067 37.72 0218 1.939 27 41 0343 1.887 13.74 0436 1.503 767 0216 3068 271 BO 0 300 2900 20510 0436 2.624 12440 0600 2300 64 36 0237 4.026 1.0560 0337 3.826 619 a 0531 3438 4603 0674 3.152 311 1 0.260 6 065 8,206 0432 5 761 6,346 0.718 5187 3,762 0864 4897 2,816 0.322 7981 32,360 0 500 7625 25,775 0.675 6875 15,360 0 906 6613 14,679 0.365 10020 101,000 0500 9750 68,110 1 125 8.500 44,371 0375 12.000 248.800 0500 11.750 223,970 t 312 10.126 106.461 0250 13.500 446,400 0375 13.250 406,394 0500 13000 371,290 0250 15 500 894.660 0375 15 250 824.601 0 500 15 000 759,375 0250 17500 1.641.309 0375 17250 1.527.400 0 500 17000 1,419,900 0.250 19 500 2,619,500 0375 19250 2.643352 0 500 19000 2,476,099 0750 23 500 7.167.030 0375 23250 6.793.832 0 500 23000 6.436.300

0.00371 0.00300

0.00600 0.00499 0.00362 0.00196 0.01414 0.01225 0 00976 000660 0.02330 OD2050 0.01656 0.01232 0 05130 004587 0.03755 002685 0.08840 0 07986 006447 0 05419 0 2006 0 1810 0 1469 0 1308 0.3474 0 3171 0.2578 0 2532 0.5475 0.5185 0.3941 07854 07528 0 5592 0 9940 0 9575 09211 1 310 1 268 1 227 1 670 1 622 1575 2074 2 021 1 969 3012 2 948 2 063

1.933 1.933 1.933 1.933 1,827 1,672 1.595 3.451 3.451 3,451 3,461 3,261 2,965 2,647 2,103 2.103 2,103 2,103 1.986 I.819 1.735 3,466 3,466 3,468 3,468 3,277 3,000 2,861 5,720 5,720 5,720 5,720 5.405 4.948 4,719 9,534 9,534 9,534 9,534 9,010 0,247 7,866 1,672 1,672 1,672 1,672 1.580 1.446 1.379 2,777 2,777 2,777 2,777 2,624 2,402 2.291 4,494 4,494 4,494 4,494 4,247 3.867 3,707 7,226 7,226 7,228 7.228 6,631 6,253 5,963 1,469 1,469 1,469 1,469 1,388 1.270 1.212 2,486 2,468 2,486 2.486 2,351 2,152 2,053 4,617 4,617 4,617 4.617 4,363 3,994 3.809 6,284 6,284 6,284 6,284 5.939 5.436 5.185 1,640 1.640 1,640 1,640 I.550 1,419 1,353 2,552 2,552 2,552 2,552 2,412 2,207 2.105 4,122 4,122 4.122 4,122 3,695 3,566 3,401 6,069 6,069 6,089 6,089 5,754 5,267 5,024 1,438 1,439 1,439 1,439 1,359 1,244 1,187 2,275 2,275 2,275 2,275 2,150 1,968 1,877 3.978 3.978 3.978 3,978 3,760 3.441 3,282 5,307 5,307 5,307 5,307 5,015 4,590 4,376 1,206 1.205 1,205 1,205 1,139 1.042 994 2,062 2,062 2,062 2,062 1,946 1.783 1.701 3,759 3,759 3,759 3,759 3,552 3,251 3,101 4,659 4,659 4,659 4,659 4,403 4,030 3,844 1,098 1,098 1.098 1.098 1.037 950 906 1.864 1.664 1.664 1,664 1.761 1,612 1.537 3,554 3,554 3,554 3,554 3,359 3,074 2,932 3,699 3,699 3,699 3,699 3,496 3,200 3.052 1,022 1,022 1,022 1,022 966 664 643 1,484 1,484 1,484 1,464 1.403 1.264 1,224 3,736 3,736 3,736 3,736 3,531 3,232 3,082 976 976 976 976 922 644 805

1,245 1,245 1,245 1,245 1,177 1,077 1,027 3,113 3.113 3,113 3,113 2,942 2,693 2,566 466 466 466 486 460 421 401 607 a07 807 607 763 698 666

1.132 1,132 1,132 1,132 1,069 979 934 425 425 425 425 402 368 351 705 705 705 705 666 609 581 987 967 967 987 933 654 a15 377 377 377 377 357 326 311 625 625 625 625 591 541 516 876 876 876 676 a23 757 722 339 338 339 339 321 293 280 562 562 562 562 531 466 464 767 767 767 767 743 680 649 282 262 262 282 267 244 233 466 467 467 467 442 404 366 660 654 654 654 618 565 539

'ASTM Al06, grade 6 seamless pope-petroleum refinery plplnq code for pressure p!p~ng ANSI 631.3.1976-corrosnn allowance=0 05

Exotic Metals. In some highly corrosive environments, especially those associated with CO;! floods, stainless- steel pipe has been employed. This is extremely expen- sive. However, it may be the only acceptable long-term solution.

Pressure Ratings for Steel Pipe

Pipe-Wall Thickness. Water-injection lines may have to withstand extremely high pressures. In addition, some of the piping in the plant may include high-pressure gas, oil, or water piping. Thus, steel pipe-wall thicknesses other than “standard” weight may be needed.

The thickness for any pipe depends on the pressure rating, temperature, diameter, and piping code ap- plicable to that pipe. Piping codes generally used are: (1) ANSI B31. l-power piping,’ (2) ANSI B31.3-chem- ical plant and petroleum refinery piping, lo (3) ANSI B31.4- liquid petroleum transportation piping systems, ’ ’ and (4) ANSI B3 1. S-gas transmission and distribution piping systems. I2

Generally, B31.1 and B31.3 have the same equation for determining pipe thickness. This tends to be more conservative than that contained in the other two codes. Wall thicknesses determined from this equation are shown in Table 15.3. These are primarily used for steam piping at all locations, for all piping on offshore plat- forms, and in large onshore plants that represent a large capital investment.

B3 1.4 and B3 1.8 have the same equation for pipe-wall thickness. The allowable pressure in a given pipe is dependent on the “construction factor.” which is a measure of the potential cost of failure at a given loca- tion. The greater the hazard to the public because of failure, the smaller the construction factor. Allowable pressures for various grades of steel and construction factors are given in Table 15.4 and 15.5.

Generally, oil or water lines can be specified with a construction factor of 0.72. The factor for lines contain- ing gas depends on the location of the line. Table 15.5 indicates, in general, the factors to be used. However, care should be taken, since there are specific definitions

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15-12 PETROLEUM ENGINEERING HANDBOOK

TABLE 15.4-GAS TRANSMISSION AND DISTRIBUTING PIPING SPECIFICATIONS FOR CARBON STEEL AND HIGH YIELD STRENGTH PIPE’

Allowable wchnq PreSS”leS UP to 25o~F

and APISLX pope having the same wafted minimum yleld strength Itcable 10 “Liquid Petroleum Transportation Plpmg Code,” ANSI 831

Page 13: Surface Facilities for Waterflooding and Saltwater Disposal.

SURFACE FACILITIES FOR WATERFLOODING & SALTWATER DISPOSAL 15-13

TABLE 15.5-CONSTRUCTION TYPE DESIGN FACTOR, F

Construction General

Type F A 0.72 B 0.6

C 0.5

D 0.4

Description

oil field and sparsely populated area semideveloped areas and lease

facilities commercial and residential subdivided

areas and compressor stations heavily congested areas with multistory

buildings

in B3 1.8 and in the Dept. of Transportation regulations governing gas transmission lines and gathering lines within subdivisions for what factor to use. These detail definitions should be consulted for lines approaching or crossing roads and railroads, and for lines in built-up areas.

Pressure Rating Classes. Flanges and fittings common- ly used in the oil field are purchased in accordance with one of the two following specifications: (1) ANSI B16.5-pipe fittings and flanged fittings I3 or (2) API Spec. 6A-wellhead equipment. l4 These specifications establish dimensional standards, allowable pressure ratings, method of production, material properties, and

inspection and test procedures for specific piping classes. ANSI has seven classes of piping, each one of which has a table similar to Table 15.6 that specifies the pressure rating for fittings of dimensions applicable to that class. The pressure rating is a function of material and temperature. Most oilfield piping falls in Material Group 1.1. The pressure ratings for this group are

presented in Table 15.7. API has seven piping classes, which are listed in Table

15.8. API classes are rated at 100°F and are reduced 1.8% per 50°F increase in temperature to a maximum allowable temperature of 450°F. The API metallurgy and testing requirements are more strict than those for ANSI. As a result, although API 2,000 to 5,000 classes have the same dimensions as some of the ANSI classes, the API classes are rated for higher pressures.

Determination of Pressure Breaks. When piping rated for a certain pressure meets piping rated for a lower pressure, a “piping break” occurs. On one side of this break, a higher pressure is possible, while on the other side a relief valve protects the pressure from exceeding a lower pressure regardless of the manipulation of in-

dividual valves. In determining the location of a pressure break in a piping system, the following assumptions are made.

1. Check valves. will leak, allowing communication back to the upstream side of a high downstream pressure resulting from an upset condition.

2. Control valves will leak, allowing pressure to be equal on both sides if flow is stopped.

3. Shut-in sensors cannot be relied on to keep pressure from building up, unless they are installed as two com- pletely independent systems with two completely nzdun- dant shut-in valves.

4. All block valves must be assumed to be either opened or closed in such a manner as to exert maximum pressure on the pipe.

In determining pressure breaks for a complex facility, it is necessary to have a complete mechanical flow sheet that shows all piping and valves. Potential problems can develop when the wrong valve or valve combination is turned at the wrong time. The only way to protect against this contingency is to be able to see the potential paths of communication from one system to another on a mechanical flow sheet.

General Piping Design Considerations

Design Flow Rates and Pressures. The design flow rates and pressure given by the reservoir studies must be used with some judgment by the facilities design engineer. Many unknowns enter the simulations and assumptions used in arriving at these numbers.

It is the designers’ responsibility to balance the higher cost of providing additional capability to handle greater- than-expected flow rates and pressures with the risk- discounted cost of having to make these adjustments at some future date. This development of a “comfort level” for design is extremely complex and must take in- to account the availability of funds, the length of the project, the cost associated with having a surface facility limitation on potential flow rates, etc.

Care should be taken to include flow surges in the pip- ing design. This is particularly true for gas-lift source wells where instantaneous surges of as much as 50% can occur. However, it is also true for all other piping com- ponents where instantaneous rates may exceed average daily rates because of changes in operating conditions, action of pressure control and level control valves, pig- ging operations, etc.

TABLE 15.6-CLASS 150 PRESSURE (psig)-TEMPERATURE (OF) RATINGS FOR VARIOUS MATERIAL GROUPS

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15-14 PETROLEUM ENGINEERING HANDBOOK

TABLE 15.7-ANSI PRESSURE RATINGS FOR MATERIAL GROUP

1.1.

Allowable Pressure (psig)

Class - 20 lo 1 OO°F 101 to ZOOoF

150 285 260 300 740 675 400 990 900 600 1,480 1,350 900 2,220 2,025

1,500 3,705 3,375 2,500 6,170 5,625

Looped Networks. In large gathering and distribution systems, the potential savings associated with looping the system (i.e., installing pipelines parallel to existing lines to increase the system’s capacity) or installing pumps at different locations must be investigated. Although simple loops may be calculated by hand, the ready availability of many fine looped-network computer models make this a fairly easy choice. In most instances, some simple calculations and assumptions can be made that narrow the choices to a few practical alternatives. An experienced engineer can use these techniques to greatly reduce computer time and costs.

Gravity Systems. In gravity-systems design, careful consideration must be given to pressure drops in the pipe. Valves and fittings must be considered in these calculations since there is normally little room for error. It is absolutely necessary that accurate elevations of all tanks and equipment and an accurate profile be deter- mined along the line of the pipe. The hydraulic gradient must be plotted along this profile for worst-case condi- tions of working levels in the tanks or operating pressure in vessels. The hydraulic gradient should be higher than the pipe at each point to ensure that a syphon is not developed. Fig. 15.7 shows an example profile.

High-point vents should be installed in the line to keep gas from accumulating and potentially blocking the flow. Gas eliminators such as those used in lease automatic custody transfer (LACT) units can be installed for this purpose.

Pigging. On long lines where paraffin, scale, or solids may be deposited, periodic pigging of the line may be re- quired. A pig is a sphere or cylinder, often containing scrapers, which is injected into the line at the beginning in a “pig launcher” and collected in a “pig trap” at the end.

Launchers and traps must be installed wherever the pipeline changes size and at all junction points. Where pigging is expected, care must be exercised in selecting valves and radius of curvature of the pipe to allow the pig to move through the line. Fig. 15.8 shows a typical pig trap which can be used to remove a pig from a line without having to shut in flow.

Selecting Pumps and Drivers Pumps are used in all water gathering, treating, and disposal systems. Indeed, the most costly single piece of equipment in a water-injection system is often the injec- tion pump and driver, The factors to consider in the selection of pumps include capacity, head, suction lift,

TABLE 15.8-API PRESSURE RATINGS

Class

2,000 3,000 5,000

10,000 15,000 20,000 30,000

Allowable Pressure ANSI Dimensional Equivalent

at lOOoF Rating at lOOoF (Psi) Class (Psi)

2,000 600 1.480 3,000 900 2;220 5,000 1,500 3,705

10,000 - - 15,000 - - 20,000 - - 30,000 - -

space, efficiency, flexibility to varying throughput and pressure conditions, and type of prime mover. It is beyond the scope of this chapter to discuss any of these in detail. Instead, a broad description of commonly used pump types and their characteristics, types of drivers and their characteristics, and some comments as to pump piping and installation are presented.

Pump Types

There are many types of pumps in use. However, most of the common ones can be classified as either positive displacement or centrifugal by the action they employ to move the liquid to a higher pressure level.

Positive-Displacement Pumps. Positive-displacement pumps employ a moving piston, plunger, diaphragm, or rotor to move a fixed volume of liquid per revolution of the pump. The amount of liquid pumped per revolution is independent of the speed of the pump or the discharge pressure.

Reciprocating pumps are positive-displacement pumps that operate as a result of the movement of a piston or plunger inside a cylinder. Piston pumps can be double-acting in that the fluid could be forced out of the cylinder into the discharge piping ahead of the piston and liquid drawn into the cylinder behind the piston regardless of the direction of the piston travel. If liquid is pumped during a piston movement in one direction only, the pump is classified as single-acting. Pumps with two cylinders are called “duplex,” three cylinders “triplex,” etc.

Advantages of reciprocating pumps are (1) for a given speed, the rate of discharge is practically constant, regardless of head, and the pump is limited only by the power of the prime mover and the strength of the pump parts; (2) efficiency is high regardlesss of the head and speed; (3) owing to low operating speed and the low velocities of fluids, they are well adapted to handling viscous fluids; (4) they are usually self-priming.

Disadvantages of reciprocating pumps include (1) heavy weight and large physical size; (2) valve trouble can occur, especially when pumping liquid containing solids; (3) pulsating flow in both suction and discharge lines; (4) high net positive suction head requirements; (5) not generally suitable for handling liquids containing solids, abrasives, or dirt.

Rotary pumps are positive-displacement pumps that operate by having a rotating member turn inside a hous- ing in such a way that it creates one or more cavities that move from suction to discharge forcing the trapped liq- uid through the pump.

Page 15: Surface Facilities for Waterflooding and Saltwater Disposal.

SURFACE FACILITIES FOR WATERFLOODING & SALTWATER DISPOSAL

PROFlL E- MAIN LINE

Fig. 15.7-Profile of the main line in a gravity system.

Advantages of rotary pumps are (1) in general, these are the same as for reciprocating pumps; (2) rotary pumps are relatively inexpensive and require small space; (3) they will operate over wide ranges of capacity, head, and viscosity; (4) rotaries are self-priming and are good vapor-handlers; (5) they deliver relatively pulsation-free flow.

Disadvantages of rotary pumps are (1) close clearances and/or rubbing contacts restrict the choice of materials for construction; (2) close clearances require that liquids to be pumped have lubricating value and be noncor- rosive-therefore, they are suitable for oil but not suited for water; (3) rotaries have low volumetric efficiency at low speeds because the slip approaches the displace- ment. This effect increases directly with the pres- sure/viscosity ratio.

The diaphragm pump is a type of reciprocating positive-displacement pump that operates by the action of a diaphragm moving back and forth within a fixed chamber. Raising the diaphragm creates a vacuum, drawing liquid (or air) into the pump through the suction check valve. Lowering the diaphragm forces the liquid (or air) out through the discharge check valve. This type of pump will handle clear water or water containing large quantities of mud, sand, sludge, and trash. Its popularity for low-volume applications stems from its ability to operate where the quantity of water varies considerably so that much of the time air is being pumped. The suc- tion effect of the diaphragm motion makes the pump self-priming. For high discharge pressure requirements, diaphragm pumps are limited to very low fluid rates. Although they tend to be easy to repair in the field, the frequency of maintenance required is higher than with other pump types.

Centrifugal Pumps. A centrifugal pump contains a cen- tral rotating wheel, called an impeller, which imparts high velocity to the liquid by centrifugal force and then

converts most of this velocity to pressure. The liquid flows from the pump even against considerable discharge pipe pressure. By its very nature, the cen- trifugal pump operates at relatively high rotative speeds. It is the most common type of pump used today.

Centrifugal pumps can be of radial-flow construction, axial-flow construction, or some combination of the two. In radial-flow pumps, flow enters the center of the wheel and is propelled radial to the outside. Radial construction provides maximum head per stage.

Axial flow pumps develop their head by the propelling or lifting force developed in the fluid by the impeller vanes, which, in cross section, are shaped like airfoils. The flow is parallel to the pump shaft axis. The diameter of the impeller is the same at the suction and discharge sides. Velocity energy is converted to pressure by sta- tionary diffuser vanes.

Advantages of centrifugal pumps are (1) simple con- struction, quiet operation; (2) inexpensive; (3) small space requirement in relation to capacities; (4) no close clearances, therefore, it can handle liquids containing dirt, abrasives, large solids, etc.: (5) low maintenance, dependable; (6) low net positive suction head re- quirements; (7) capacity adjusts automatically to changes in head. Thus, capacity may be controlled over a wide range at constant speed.

Disadvantages of centrifugal pumps are (1) cannot achieve high pressures like reciprocating pumps; (2) viscosity effects on head, capacity, and efficiency are appreciable at 200 Saybolt Universal Seconds (S.S.U.) and serious at 500 S.S.U.; (3) low efficiencies when compared to reciprocating pumps; (4) efficiency is a function of flow rate. At throughput rates and pressures less than design, considerable additional horsepower may be required.

Pump Drivers

Depending on the location, type of pump, availability, and cost of natural gas for fuel, pump drivers will be gas

Page 16: Surface Facilities for Waterflooding and Saltwater Disposal.

15-16 PETROLEUM ENGINEERING HANDBOOK

Fig. 15.8—Pig trap.

engines, gas turbines, or electric motors. The amount ofhorsepower required for a given installation can becalculated from

qLApP&‘-z 9LZYL

1714E,3960E, , . . . . . . . . . . . . . . . (17)

wherePbh = brake horsepower,qL = flow of liquid, gal/mitt,AP = differential pressure, psi,Ep = pump efficiency at flow conditions, %

Z = head of liquid, ft, and *ye = specific gravity of liquid relative to water.

Bump efficiencies of between 80 and 90% forreciprocating pumps and 55 and 65% for centrifugalpumps are common.

Natural Gas Engines. The reciprocating internal-combustion natural-gas engine is the leading primemover in the oil field because of its high efficiency,availability, and ease of maintenance. Both two- andfour-cycle engines are in use.

In general, for a given engine, the horsepower outputdepends on engine speed in rev/min and whether anexhaust-gas turbocharger is installed to increase the flow

of air to the power cylinders. At higher operating speed,the engine is capable of producing greater horsepower. Aturbocharged engine will be able to develop morehorsepower than a naturally aspirated engine. Unfor-tunately, maintenance costs and downtime increase as anengine is accelerated above a certain limit and when tur-bochargers are added. A turbocharged engine has theadded disadvantage of being able to load itself tomechanical destruction.

Most engine drivers are built to operate in the 900- to1,400-rev/min range. For sustained operations, mostmechanics do not like to operate their engines above1,000 to 1,200 rpm. Turbocharged engines can be ex-pected to use 7,000 to 8,000 Btu/bhp-hr of fuel whilenaturally aspirated units will use 8,000 to 10,000Btu/bhp-hr. Fuel efficiency is fairly constant over largeranges in bhp.

Care must be exercised with nitric and nitrous oxide(NO,) emissions on large installations (over 2,000 hp)or in nonattainment areas. Catalytic converters areavailable for most engines if this becomes a problem.

Gas Turbines. Gas turbine engines have three basic sec-tions-an air-generation section, a combustion section,and a power-turbine section. In the compressor, or air-generator section, ambient air is drawn into the turbine

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SURFACE FACILITIES FOR WATERFLOODING & SALTWATER DISPOSAL 15-17

and compressed with a combination of radial and axial flow elements for delivery to the combustion section. Fuel is mixed with the air in the combustion section and the combustion products am mixed with additional air to provide a specific temperature at the power turbine inlet. The hot gas expands across the power turbine providing power to drive the air generator and the load.

Advantages of turbines over gas engines include the following.

1. Gas turbines can be made very light and compact in relation to horsepower (‘/4 to ‘/2 Ibm/hp) in jet aircraft. The weight/horsepower ratio varies from 1 to 12 lbm/hp for industrial turbines. High-speed turbocharged gas engines weigh from 15 to 40 lbm/hp.

2. Turbine maintenance cost is normally lower and its availability higher. This is true, however, only for tur- bines in continuous service. Starting and stopping units has a severe effect on maintenance costs.

3. Turbines reject large quantities of high-temperature heat in their exhaust, which can be used to provide proc- ess heat.

4. Turbines are available in larger sizes (100,000 hp and higher).

5. Turbines are clean burning from an air pollution standpoint and do not require catalytic converters.

Disadvantages of turbines are (1) high fuel consump- tion if waste heat is not needed (9,000 to 11,000 Btu/hp- hr at peak efficiency) and (2) large falloff in fuel effi- ciency when operating at less than peak load.

Electric Motors. In areas where electricity is available from either commercial sources or onsite generators, electric-motor drives are the least expensive in initial capital and maintenance costs. Their use is recommend- ed where the additional cost of purchasing or generating electricity is not too great.

Pump Piping and Installation Details

Suction Piping. It is essential that a flooded suction be furnished for reciprocating pumps. A pump should never be allowed to run “dry” or “starved.” The net positive suction head (NPSH) recommended by the manufacturer is shown on the performance curves for the pump and must be provided. To furnish this head and ensure a flooded suction at all times, it is necessary that (1) the storage tank or basin supplying the pump be set at a suf- ficient elevation above the fluid end of the pump and (2) that the suction piping be of sufficient size to minimize friction losses in the pipe between the storage tank or basin and the pump. In cases where it is possible to secure sufficient elevation head between the storage tank and pump, a centrifugal pump, commonly called a “booster pump,” is employed. Normally the booster pump is tied into the storage tank and delivers the water in sufficient quantity to the suction header of the reciprocating pumps to furnish the flooded suction and provide the required NPSH.

The recommended NPSH curve, supplied by manufac- turers of reciprocating and centrifugal pumps, is the NPSH that results in a 3% drop in capacity. Cavitation usually starts at a higher NPSH. In cases where no cavitation damage can be tolerated, the NPSH required for no loss in capacity should be used for designing suc- tion and charge systems.

The following features relative to suction-piping in- stallations should be provided.

1. Suction pipe should be as large as or, preferably, larger than the pump suction-inlet size. Table 15.9 in- dicates acceptable flow velocities in suction lines.

2. Long-radius elbows are recommended to eliminate sharp turns.

3. Suction lines should be laid to a constant grade from the storage tank to pump to eliminate high points where vapor may accumulate.

4. For reciprocating pumps, a pulsation dampener should be installed. These can be elastomer diaphragm or acoustic in design. One common alternative is to in- stall an air- or gas-volume chamber. The chamber allows the pump to fill properly by relieving excessive accelera- tion and deceleration of the fluid with each stroke of the pump. The required size of an air-volume chamber and its air space depends on the type of pump, displacement per revolution, and speed of the pump. The air-volume chamber may vary from two to eight times the piston displacement of a single stroke. A sight glass is also in- stalled for gauging the liquid level in the chamber so that gas or air can be added periodically to replace what is ab- sorbed by the liquid being pumped.

5. The suction piping should be flushed out and cleaned prior to starting the pump to remove slag, mill scale, rust, welding splatter, etc.

Discharge Piping. As in the suction piping, the discharge piping should be well planned with a minimum of turns, fittings, restrictions, etc. The discharge piping should be of sufficient size to minimize friction losses in the pipe to furnish the required pressure of the pump discharge. Other factors to be considered in discharge piping include the following.

1. A pressure-relief valve must be employed on positive-displacement pumps in the discharge line ahead of any other valve or restriction.

2. A pulsation damper, or desurger, should be in- stalled in the discharge line near a reciprocating pump to relieve shock or vibratory forces. These forces are the result of pressure variations, or surges, prevalent in positive-displacement pump operation. They also result from water hammer because of valve closures and restrictions in the line.

The design and theory of pulsation dampers, or desurgers, are based on the concept that a constant pressure can be maintained if the liquid can be ac- cumulated as the pressure increases and discharged as the pressure decreases. Several types of dampers, or

TABLE 15.9-TYPICAL FLOW VELOCITIES (ftlsec)

Suction Discharge velocity velocity

Reciprocating pumps Speeds up to 250

revtmin 2 6 Speeds 251 to 330

revlmin I’/2 4% Speeds above 330

revlmin 1 3 Centrifugal pumps 2 to 3 6 to 9

Page 18: Surface Facilities for Waterflooding and Saltwater Disposal.

15-18 PETROLEUM ENGINEERING HANDBOOK

desurgers, are available. Operational features should be investigated and a damper, or desurger, selected to tit each condition.

3. On installations where the fluid is pumped to a level higher than the pump outlet, a gate valve or check valve should be placed downstream of the pressure-relief valve near the pump in the discharge line. This permits shutoff of fluid backing through the pump while pump valves or plungers are being serviced.

The general practice is to connect pumps in parallel through a common suction and discharge header on systems where two or more pumps are installed. A better but somewhat more costly practice is to use separate suc- tion lines for each pump. Headers should be sized to en- sure sufficient capacity for satisfactory operation. Each reciprocating pump should have its own separate pressure-relief valve to ensure protection regardless of which pump may be shut down or out of service.

Foundations. For adequate support to maintain align- ment and to reduce vibration, a foundation of sufficient size and strength should be provided. Steel-reinforced- concrete foundations are ordinarily used for rotating equipment and are recommended for onshore locations. The pump and prime mover must be set level to ensure good operation. To accomplish this, the pump and mover are mounted on a skid base; the skid base is set on the concrete foundation, leveled, and approximately 1 in. of grout is used to set the equipment.

The required dimensions of the foundation will vary relative to the size and shape of the equipment. The depth to which the foundation must be carried depends on the soil conditions where the foundation is to be set.

The foundation should have sufficient bearing area, which is calculated by using the allowable soil-bearing capacity. Where unbalanced forces are unknown, a rule of thumb that the weight of the concrete-mass foundation should be from 1.5 to 2 times the weight of the reciprocating equipment is sometimes used. Under cer- tain combinations of poor soil and large unbalanced forces, the foundation weight may have to be as much as four times the weight of the equipment.

The size and shape of the skid base will determine the plan dimensions of the foundation and, with acceptable soil conditions, the depth of the foundation is carried to a point that will furnish the required mass. Temperature stresses in normal concrete foundations for pumps and engines govern the amount of steel reinforcing used. The amount of such steel can be estimated by: area of steel (sq in/sq ft of slab area) =0.002 Xcross-sectional area (sq in. of concrete slab). Maximum spacing between bars should not exceed 18 in. Where unbalanced forces and couples are known and for large offshore installations where weight is important, a more detailed dynamic calculation should be made.

Separating Suspended Solids From Heater

The water that is being treated may have suspended solids such as produced sand, rust, and scales. These can be separated from the water stream by gravity settling, cyclone desanders, centrifuges, filters, or flotation.

Gravity Settling

Solid particles, because of their heavier density than water and net negative buoyant force, will settle to the bottom with a terminal velocity that can be derived fmm Stoke’s law as

A&)’ “E- 18~L, , . . . . . . . . . . . . . . . . . . . . . . . (18)

where Ap = difference in density of the particle and the

liquid, dp = solid particle diameter, and pL = viscosity of the liquid.

This equation can also be expressed as

v= l.78x10-6Ay(d,)2

, . . . . . . . . . . . . . . . . . . (19) Pw

where dp = particle diameter, microns, Ay = difference in specific gravity relative to

water,

Pw = viscosity of water, cp, and v = velocity, ft/sec.

This equation can be used to size a tank, vertical pressure vessel, horizontal pressure vessel, rectangular sedimen- tation chamber, or a device of any other configuration to allow a particle of a certain diameter and specific gravity to settle to the bottom.

Legend L, = Inlet dlstrlbubon section L- = Effective settlina action L, = Outlel gathering section

““, = Water velocity

“3 = Settling velocity 1, = Time water in effectwe sectnon of flume 1, = Time pan!cle is falling while 1” effective sectmn of flume

Zf 1s =-

“S

Le fw=-

“W

Le”S Yw=- Z f

Fig. 15.9-Model for calculation of sedimentation flume capacity.

Page 19: Surface Facilities for Waterflooding and Saltwater Disposal.

SURFACE FACILITIES FOR WATERFLOODING & SALTWATER DISPOSAL 15-19

Most sedimentation basins are rectangular flumes with length-to-width ratios of 4: 1 or greater to limit crossflow. The width of the flow channel can be deter- mined by setting the time required for a particle to settle from the top of the flume to the bottom equal to the time required for the water to traverse from the inlet of the flume to the outlet as shown in Fig. 15.9. This can be ex- pressed as

b= 369,,+4w

*y(d,)2L,, . . . . . . . . . . . . . . . . . . . . . . . . (20)

where b = width (breadth) of flow channel, ft,

4w = water flow rate, B/D, and L, = effective length, ft.

Note that the width and length of the settling chamber are independent of its de posal of Refinery Wastes IP

th. The API Manual on Dis- recommends a turbulence and

short-circuiting factor of between 1.3 and 1.8, depend- ing on the ratio of water velocity to solids settling veloci- ty. Using a factor of 1.8. Eq. 20 can be rewritten as

b= 6-%wpL,

ay(d,)‘~,’ . . . . . . . . . . . . . . . . . . ..I.. .(21)

API also recommends that water velocity be limited to 15 times the settling velocity, or 3 ft/min, whichever is less. The settling velocity can be calculated from Eq. 19 and the water velocity can be calculated from

v,=6.5x10-5~, _. . . . . . . . . . . .(22) f

where V, is the velocity of water, ftisec, and hf is the height of flume, ft. For practical considerations, b should be between 6 and 20 ft and ratio of hf to b should be between 0.3 and 0.5.

The flume can be concrete lined or constructed as a soil pit. Solids that settle in the bottom of the flume can be cleaned out with a bucket. A mechanical sludge scraper run on a chain could be installed to concentrate the solids in one location for easy removal.

Cyclone Desanders

Cyclone desanders are conical-shaped devices that make use of centrifugal force to separate the heavier particles from the liquid. Fig. 15.10 shows the basic operation of a cyclone desander. Pressurized fluid enters a common inlet manifold, which distributes the stream to individual cyclones. Flow proceeds through a tangential feed inlet, which directs the fluid against the wall of a cylindrical section above a truncated cone. The fluid and solid par- ticles move downward in a spiral pattern forcing the heavy particles to move toward the outer perimeter of the cone. Gravity forces these particles to slide downward and to be rejected at the cone apex and carried away in the “underflow” slurry. The water moves toward the vacuum created at the center of the cone, and is drawn off as the “overflow. ”

The size particle that is separated depends on the pressure drop through the cone. The pressure drop, in turn, depends on the flow rate. Thus, there is a minimum flow and a pressure drop that must be provided for each cone to settle a certain size particle. With pressure drops in the range of 25 to 50 psi, cyclones can be used to remove 99% of the 30- to lOO-micron particles.

overflow p,pe

vortex finder k?- 0

-fee0 front view

I conic01 section

i/l apex slda view

i underflow

Fig. 15.10-Hydrocyclone operation.

Page 20: Surface Facilities for Waterflooding and Saltwater Disposal.

15-20 PETROLEUM ENGINEERING HANDBOOK

Fig. 15.11 -Cartridge filter

Centrifuges

Centrifuges are used on drilling rigs to separate low- gravity drill solids and reclaim high percentages of the heavy solids. They have not found wide use in producing operations because of the high maintenance associated with their use. Normally, if it is desirable to separate par- ticles of diameter less than that resulting from sedimenta- tion or cyclones, filters are used.

TABLE lC.lO-CARTRIDGE DESIGN CONDITIONS FOR BRINE

Particle Size

Flow Rate for 3-h. OD x 3&n.

Element Cartridge Type

Pleated wire screen

(microns)

80

(gallmin)

12

Pleated cellulose paper 5to10 4

Rolled laminated cotton and acrylic excelsior filler 5to10 2to 3

Molded fiberglass 2 6

Filtration To avoid plugging the injection formation it may be necessary to separate small-diameter suspended particles by filtration. Filters cannot handle the volume of solids that can be handled by sedimentation and cyclones. By proper choice of filter element, filters can remove fine solids in the 0.5- to 50-micron range and are used as a form of secondary treatment.

Cartridge Filters. Cartridge filters are the simplest to install, require no backwash, and are capable of remov- ing solid particles of %-micron or larger diameter. Their drawback is that they can take only very low solid loadings. The filter vessel must be taken out of service, depressurcd, and the cartridges replaced whenever the volume of solids trapped causes the differential pressure to exceed a predetermined maximum (usually 25 psi). Some modem cartridge filters can be backwashed.

Fig. 15.11 shows a typical cartridge filter. The cylin- drical filters arc encased in a pressure vessel. Flow enters the vessel and flows from the outside of the car- tridges to the center, where it enters a perforated pipe that is open on the bottom. A bypass mechanism is in- cluded that will automatically allow flow to pass from the inlet to the outlet chambers if the differential pressure exceeds the capacity of the cartridges.

Table 15.10 indicates the particle size that can be separated and the recommended flow rate through various standard-size cartridges. The molded fiberglass has the least solid storage area and the pleated wire screen and pleated paper the most.

Sand Filters. Sand filters have beds of graded sand, gravel, anthracite, or graphite. The beds may be of a single medium or may be graded from coarse to tine media to allow for greater solids loading.

The media are arranged in a pressure vessel for either downflow filtration and upflow backwash as shown in Fig. 15.12 or for upflow filtration and upflow backwash. Conventional downflow filters arc limited to flow rates of 2 to 5 gal/(min-sq ft) and total solids loads (before backwashing) of % to 1% lbmlsq ft. With appropriately designed distribution systems, high-rate filters can be operated at 7 to 15 gal/(min-sq ft). This higher loading forces the solids farther into the bed allowing for solid loadings of between 1 and 4 lbmisq ft.

Upflow filters have a greater capacity for solids loading. Flow tends to loosen the bed allowing for greater penetration of the solids. This allows up to 6 lbm/sq ft of solid loading. However, because of the danger of losing the bed, upflow filters are limited to flow rates of 6 to 8 gal/(min-sq ft). They also require longer backwashing time and more backwash fluid.

Walnut hulls are used as filter media in some new filters. There is a system that removes, cleans, and returns this medium to the filter automatically.

Sand filters are good for separating 25-micron par- ticles. Some manufacturers claim their filters are good for 5- to lo-micron separation.

Diatomaceous Earth (DE) Filters. For filtration of O.S- to l.O-micron particles, DE filters arc used. Typically, these have low solids-loading capabilities [‘/z to 1 gal/(min-sq ft)]. A typical DE filter is shown in Fig. 15.13.

Page 21: Surface Facilities for Waterflooding and Saltwater Disposal.

SURFACE FACILITIES FOR WATERFLOODING & SALTWATER DISPOSAL 15-21

The individual leaves, which are spaced at approx- imately 3-in. intervals, are made up of a wire screen of corrosion-resistant materials such as stainless steel, Monel@, or Inconel@. A precoat slurry of DE is mixed and flowed through the filter to provide an approximate- ly x6-in.-thick coating to the leaves. Flow then is turned into the filter with a “body feed” of “filter aid” (DE and cellulose fiber or perlite) equal on a weight basis to the amount of solids to be filtered. The body feed helps to build an even, permeable filter cake on the leaves.

When a pressure differential of 25 to 35 psi is reached, the unit must be taken out of service and the filter cake removed. This can be done by backwashing alone, backwashing and vibrating, or backwashing and water sluicing the cake. Water with good filtering characteristics may build up a large permeable filter cake that requires backwashing before a large pressure dif- ferential is developed.

Flotation

It is possible to remove small particles by use of dis- persed or dissolved-gas flotation devices. These units are used primarily for treating hydrocarbons from water and are discussed in that section. Normally gas is dispersed into the water or released from solution in the water and forms bubbles approximately 30 to 120 microns in diameter. The bubbles form on the surfaces of the suspended particles and create a particle whose average density is less than that of water. These rise to the sur- face and are mechanically skimmed. Because of the dif- ficulty of predicting particle removal efficiencies with the method, it is normally not used in oil field land operations. However, it is being used increasingly in off- shore operations and in some underground disposal systems.

Treating Hydrocarbons From Water Produced water, which may have to be treated, will enter the water treating plant from a three-phase separator, free water knockout, gun barrel, heater treater, or other lease equipment, which arc discussed in previous chapters. This water will contain small amounts (100 to 2,000 mg/L) of suspended hydrocarbons in oil droplets. Since the water flows out of these pieces of equipment through dump valves or pumps, the oil particle diameters will be very small.

Theory

Treating equipment to handle this problem relies on one or more of the following principles: gravity separation of the lighter oil droplets from the water, coalescence of the smaller oil droplets, or gas flotation of the oil droplets. In applying these concepts, one must keep in mind the dispersion of large oil droplets to smaller droplets, which will take place if energy is added to the system.

Gravity Separation. As in the case of settling of sand from water, Stoke’s Law, Eqs. 18 and 19, holds true for the buoyant rise velocity of an oil droplet in a water- continuous phase. Several immediate conclusions can be drawn from this equation.

1. The larger the size of an oil droplet, the greater its vertical velocity. That is, the bigger the droplet size, the

BACKWASH OUTLET

CLEAN WATER OUTLET I

RAW WATER INLET

#

BACK’4 INLET

‘ASH

Fig. 15.12-Sand filter

less time it takes for the droplet to rise to a collection sur- face and thus the easier it is to treat the water.

2. The greater the difference in density between the oil droplet and the water phase, the greater the vertical velocity. That is, the lighter the crude, the easier it is to treat the water.

3. The higher the temperature, the lower the viscosity of the water, and thus, the greater the vertical velocity. That is, it is easier to treat the water at high temperatures than at low temperatures.

The last conclusion requires some further elaboration. Heat is the primary mechanism used in treating small water droplets from oil in oil-treating equipment because of the effect heat has on the oil viscosity, which prompts more rapid settling, and because of the effect heat has on the emulsifier stabilizing the water-in-oil emulsion. Heat is not commonly used in water treating because (1) the percentage change in viscosity per degree of temperature change is much greater in oil than in water, (2) water-in- oil emulsions tend to have a higher percent of the dispersed phase than oil-in-water emulsions, and the dispersed phase tends to have larger-diameter droplets stabilized by heat-sensitive emulsifiers, and (3) it takes twice as much heat input to raise a barrel of water as it takes to raise a barrel of oil to the same temperature.

Page 22: Surface Facilities for Waterflooding and Saltwater Disposal.

PETROLEUM ENGINEERING HANDBOOK

OS TYPE SEAL ARRANGEMENT

Fig. 15.13-Typical diatomaceous earth filter.

TYPE ff LEAVES SEAL TYPE 1 !SHELL MA r I MUMEGAI- IMDTCftHPl sLuoGEo.lFt I lwrf wEwrl FILTER ARCAl 1 ND LEAVES 1 TECHNICAL DATA

Dispersion. The small oil droplets contained in the water-continuous phase are subject to continuous disper- sion and coalescence. An oscillating droplet of oil will become unstable when the kinetic energy is sufficient to make up for the difference in the surface energy between the single droplet and the two smaller droplets formed from it. At the same time that this process is occurring, the motion of the smaller oil particles is causing coalescence to take place. Therefore, it should be possi- ble to define statistically a maximum droplet size for a given energy input per unit mass and time at which the rate of coalescence equals the rate of dispersion.

The size of the oil droplets that will exist is a function of one over the amount of work done on the liquid per unit mass per unit time. This can be shown to be a func- tion of the pressure drop as

&i)max = -k,, . . . . . . . . . . . . . . . . . . . . . (23) &

where

(hi) mm = maximum droplet diameter, t = time,

A, = pressure drop experienced by the liquid in time t and

Cd = dispersion constant.

The greater the pressure drop, and thus the shear forces that the fluid experiences in a given time period, the smaller the oil droplets will be. Large pressure drops.

which occur in small distances through chokes, control valves, cyclone desanders, etc., result in small oil droplets and water that is harder to treat. A pressure dmp of 50 to 75 psi will result in a maximum particle size of 10 to 50 microns.

The dispersion process is theoretically not instan- taneous. However, it appears from field experience to take place very rapidly. For design purposes, it could be assumed that whenever large pressure drops occur, all droplets will disperse instantaneously. This is, of course, a conservative approximation.

Coalescence. Within water-treating equipment, where the energy input to the fluid is very small, the process of coalescence takes place. That is, small oil droplets col- lide and form bigger droplets. Because of the low energy input these are not, in turn, dispersed.

Coalescence can also occur in pipe downstream of pumps and control valves. However, in such instances, the process of dispersion will govern the maximum size of stable oil droplet that can exist. For normal pipe diameters and flow velocities, particles of 500 to 5,000 microns are possible.

The process of coalescence in water-treating systems appears to be more time dependent than the process of dispersion. When two oil dmplets collide, contact can be broken before coalescence is completed because of tur- bulent pressure fluctations and the kinetic energy of the oscillating droplets.

Page 23: Surface Facilities for Waterflooding and Saltwater Disposal.

SURFACE FACILITIES FOR WATERFLOODING 8 SALTWATER DISPOSAL 15-23

The time it takes to “grow” a large droplet from a relatively small droplet, in a “quiet” gravity settler, is approximated by

(4b4 r=- .,,...........,...............

2f vK, ’ where

dd = droplet diameter, fv = volume fraction of the dispersed phase, and K, = empirical settling constant.

While it is impossible to determine K, for an actual in- stallation, the following qualitative conclusions can be

drawn. 1. A doubling of residence time will cause an increase

in droplet size of only 19 % 2. The more dilute the dispersed phase, the greater the

residence time needed to grow a given particle size. That is, coalescence occurs more rapidly in concentrated dispersions.

Gravity Separation Devices

Most water-treating equipment makes use of gravity separation of the oil droplets. Included in this categoty are skim tanks, API separators, plate coalescers, and skim piles. Unfortunately, it is necessary to know both the oil concentration in the effluent water and the particle size distribution to design a gravity separator to meet a certain effluent quality.

This information can be determined from experience- derived relationships such as those shown in Fig. 15.14. Further work is needed to define these relationships. For the present, the design engineer must rely on a judgment factor or on laboratory tests for the particular crude oil and water.

Skim Tanks and Vessels. The simplest form of treat- ment equipment is a skim tank or pressure vessel. These are normally designed to provide large residence times during which coalescence and gravity separation can oc- cur. They can be either pressure vessels or atmospheric tanks.

Skim tanks can be either vertical or horizontal in con- figuration. They may be set up for vertical downward flow of the water with or without inlet spreaders or outlet collectors. They may also be designed as horizontal vessels where the water enters on one side and flows over a weir on the far end.

In vertical vessels the oil droplets must flow upward against the downward velocity of the water. For this reason, horizontal vessels are more efficient in gravity separation of the two liquid phases. In spite of this, ver- tical vessels and tanks are sometimes used for two reasons.

1. Sand and other solid particles can be more easily handled in vertical vessels with either the water outlet or a sand drain off the bottom. Experience with elaborately designed sand drains in the large horizontal vessels has not been very satisfactory.

2. Vertical vessels are less susceptible to high-level shut-downs because of liquid surges. Internal waves resulting from surging in horizontal vessels can trigger a level float even though the volume of liquid between the

DROPLET SIZE

Fig. 15.14-Form of empirical curves for oil concentration and droplet size distribution.

normal operating level and the high-level shut-down is equal to or larger than that in a vertical vessel.

Tracer studies have shown that large skim tanks, even those with carefully designed spreaders and baffles, ex- hibit poor flow behavior and short circuiting. This is probably because of density and temperature differences, deposition of solids, corrosion of spreaders, etc. In one case, a tank with a design mean residence time of 33 hours had a breakthrough of the tracer with a peak within minutes of tracer injection.

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15-24 PETROLEUM ENGINEERING HANDBOOK

As seen previously, the provision of residence time to allow for coalescence does not appear to be cost effi- cient. However, a minimum residence time of 10 minutes to one hour should be provided to ensure that surges do not upset the system and to provide for some coalescence.

Horizontal Pressure Vessel Si&zg. The required diameter and length of a horizontal cylinder operating one-half full of water can be determined by use of a model similar to that used for settling solids. The follow- ing equation can be derived from the model.

diL,= l~q,cL, *y,,(dd)2 . . . . . . . . . . . (25)

where di = vessel ID, in.,

qw = water flow rate, BWPD,

CL, = water viscosity, cp, dd = oil droplet diameter, micron, L, = effective length in which separation occurs,

ft (for design use 75% of the seam-to- seam length), and

AYOW = difference in specific gravity between oil and water.

While Eq. 25 will govern the design, it is also necessary to check for adequate retention time.

t,=0.7(di)2Le . . . . . . . . . . . . . . . . . . . . . (26)

where t, is the retention time in minutes. Vertical Cylindrical Vessel. The required diameter of

a vertical cylindrical pressure vessel or tank can be deter- mined from

(d;)~=7,oooF qwpw AYow(dd)2 , . . . . . . . ..(27)

where F is a factor to account for turbulence and short circuiting. For small-diameter vessels (48 in. or less), F= 1 .O. For larger diameters, F depends on the type of inlet and outlet spreaders, collectors, and baffles that are provided. Large tanks (10 ft or more in diameter) should be considered to have an F> 2.0, depending on the inlet and outlet conditions. Tanks greater than 10 ft in diameter should be discouraged because of short circuiting.

The height of the water column can be determined from retention time requirements:

rrq, z,=o.7- (di)2 , . . . . . . . (28)

where Z, is the height of the water column in feet.

API Separators. An API separator is the name given to a horizontal, rectangular cross-section, atmospheric oil skimmer that follows the sizing equations and guidelines included in the API Manual on Disposal of Re@ery Wuszes. l5 Fig. 15.15 shows a typical API separator. The equations for sizing and their derivations have been discussed previously in the solids settling section.

Plate Coalescers. The use of flow-through parallel plates to help the gravity separation in skim tanks was pioneered in 1959 l6 as a method of converting existing API separators to treatment of droplets less than 150 microns in diameter.

Various configurations of plate coalescers have been devised. These are commonly called parallel plate in- terceptors (PPI), corrugated plate interceptors (CPU, or crossflow separators. All of these depend on gravity separation to allow the oil droplets to rise to a plate sur- face where coalescence and capture occur. Flow is split between a number of parallel plates spaced a short distance apart. To facilitate capture of the oil particles, the plates are inclined to the horizontal.

As shown in Fig. 15.16, an oil droplet entering the space between the plates will rise in accordance with Eq. 19. At the same time, it will have a forward velocity equal to the bulk water velocity. By solving for the ver- tical velocity needed by a particle entering at the base of the flow to reach the coalescing plate at the top of the flow, the resulting diameter can be determined. A restriction is placed on the Reynold’s number for the water to ensure that turbulence in this flow does not af- fect the oil sheet on the coalescing plate.

General Sizing Equation. For a plate coalescer with flow either parallel to or perpendicular to the direction of flow the general sizing equation for the droplet size removal is:

@A2 = 4.%wL,Pw

c*s 8 zpb,LAy,, ) . .

where dd = design oil droplet diameter, micron,

4w = bulk water flow rate, BWPD, L, = perpendicular distance between plates, in.

P !a = viscosity of the water, cp, 0 = angle of the plate with the horizontal,

Zp = height of the plate section perpendicular to the axis of water flow, ft,

b, = width of the plate section perpendicular to the axis of water flow, ft.

L = length of plate section parallel to the axis of water flow, ft, and

AY DW = difference in specific gravity between oil and water.

Experiments have indicated that Reynold’s number for the flow regime cannot exceed 400, on the basis of the hydraulic radius as the characteristic dimension. Thus the maximum flow rate is given by

(qw)max= 1562Z,b,

. . . . . . . . I.. . . I.. L P

(30)

Page 25: Surface Facilities for Waterflooding and Saltwater Disposal.

SURFACE FACILITIES FOR WATERFLOODING & SALTWATER DISPOSAL 15-25

J ‘I ii

/ ,L”DU SECTION A -A r(OPPL RS

Fig. 15.15-API oil-water separator.

Parallel Plate Interceptor (PPZ). The first form of plate coalescer was the PPI. This involved installing a series of plates parallel to the longitudinal axis of an API separator (a horizontal, rectangular cross-sectioned skimmer). The plates form a “V” when viewed perpen- dicular to the axis of flow so that the oil sheet migrates up the underside of the coalescing plate and to the sides. Sediments migrate toward the middle and down to the bottom of the separator, where they are removed.

Corrugated Plate Interceptor (CPZ). The most com- mon form of parallel plate interceptor used offshore is the CPI. This is a refinement of the PPI in that it takes up less platform space (length) for the same particle size removal, and has the added benefit of making sediment handling easier. Fig. 15.17 is a typical design using a corrugated plate.

In CPI’s, the parallel plates are corrugated (like roof- ing material) with the axis of the corrugations inclined to an angle of 45”. The bulk water flow is forced downward. The oil sheet rises upward counter to the water flow and is concentrated in the top of each cor- rugation. When the oil reaches the end of the plate pack it is collected in a vertical channel and brought to the oil/water interface. CPI’s require frequent cleaning of the plate packs where large amounts of sediments are handled.

Crossjlow Devices. Recently manufacturers have

modified the CPI configuration for horizontal water flow perpendicular to the axis of the corrugations in the plates. This allows the plates to be put on a steeper angle to facilitate sediment removal and to enable the plate pack to be more conveniently packaged in a pressure vessel. The latter benefit may be required if gas blowby through an upstream dump valve could cause relief prob- lems with an atmospheric tank.

LARGE DROPLETS RISE i? TO COLLECTION SURFACE 0 /

----OIL SHE

iilL DROPLET

Fig. 15.16-Plate coalescers.

FLO’.+

ET VELOSITY

Page 26: Surface Facilities for Waterflooding and Saltwater Disposal.

15-26 PETROLEUM ENGINEERING HANDBOOK

Fig. l&17-CPI separator flow pattern.

-QUIESCENT ZONE

- FLOWING ZONE

-OIL RISERS

Fig, 15.18-Skim pile flow pattern.

Crossflow devices can be constructed in either horizontal or vertical pressure vessels. The horizontal vessels require less internal baffling as the ends of nearly every plate conduct the oil directly to the oil/water inter- face and the sediments to the sediment area below the water flow area. The vertical units, although requiring collection channels on one end to enable the oil to rise to the oil/water interface and on the other end to allow the sand to settle to the bottom, can be designed for more ef- ficient sand removal. Crossflow separators are used where sand is considered a problem and it is not removed in the process upstream of the CPI.

Practical Limitations. Stoke’s law theory should app- ly to oil droplets as small in diameter as 1 to 10 microns. However, field experience indicates that 30 microns sets a reasonable lower limit on the droplet sizes that can be removed. Below this size small pressure fluctuations, platform vibration, etc., tend to impede the rise of the droplets to the coalescing surface. Thus, the practical limit for sizing plate coalescers is 30-micron removal.

Skim Pile. Skim piles are gravity water-treating devices that are used offshore. As shown in Fig. 15.18, flow through the multiple series of baffle plates creates quies- cent zones that reduce the distance a given oil droplet must rise to be separated from the main flow.

Once in the quiescent zone, there is plenty of time for coalescence and gravity separation. The larger droplets then migrate up the underside of the baffle to an oil col- lection system. Skim piles are used extensively to treat deck drainage of washdown or rainwater that has been contaminated with oil. They have the added benefit of providing for some degree of sand cleaning. Sand tra- versing the length of a skim pile will abrade on the baf- fles and be water washed. This removes the free oil, which is then captured in a quiescent zone.

Skim Pile Sizing-Deck Drainage. Field experience has indicated that acceptable effluent is obtained with 20 minutes of retention time in the baffled section of the pile. Using this,

(&)*,&=14.3 (q,+O.356 &q,), . . . . . . . . .(31)

where Lbs = length of baffle section, ft, Ad = area of deck, sq ft, and qr = rainfall rate, in./hr.

Intermittent Flow. During periods of no flow, oil droplets rise to the area of the quiescent zone and become trapped and protected from being swept back in- to the flow stream when flow is resumed. The net effect of the baffles is to reduce this rise distance. Each time flow is stopped as the water traverses the baffled section more oil particles are trapped in the quiescent zone.

This phenomenon can be used when it is desired to use a skim pile downstream of a skim tank or CPI for further treating. By use of a snap acting water dump on the in- fluent, intermittent flow is established in the pile.

If t is the time in seconds for the dump cycle,

NC= 41.7 (di)*Lbs

. . . . . . . . . . . . . . . . . . . . . . .(32) qwt

Page 27: Surface Facilities for Waterflooding and Saltwater Disposal.

SURFACE FACILITIES FOR WATERFLOODING & SALTWATER DISPOSAL 15-27

(b)

Fig. 15.19-(a) air flotation process; (b) circular flotation chamber details.

where N, is the number of cycles of no flow a particle sees as it traverses the baffle section.

If t, is the time the valve is closed, the removal effi- ciency on any cycle of a particular drop size is

E =4.3x10-5(A~,,)(d,)2~, rc . . . . . . . . . . . .

cl&i (33)

The overall removal efficiency of that particle size can then be determined by

E,=l-[l-E,IN,. . . . . . . . . . . . . . . . . . . . (34)

Gas Flotation Units

Flotation units are the only commonly used water- treatment equipment that does not rely on gravity separa- tion of the oil droplets. In fact, the action of these units is independent of the oil droplet size. In gas flotation units, large quantities of small-diameter gas bubbles are in- jected into the water stream. The bubbles attach to the oil droplets suspended in the stream and cause them to rise to the water surface as a froth. Experimental results have shown that very small-diameter oil droplets in dilute suspension can be removed easily by flotation. High percentages of oil removal are achieved.

Two distinct types of flotation units have been used, which are distinguished by the method employed in pro- ducing the small gas bubbles needed to contact the water. These are dissolved-gas units and dispersed-gas units.

Dissolved-Gas Units. Dissolved-gas designs take a por- tion of the treated water effluent and saturate the water with natural gas or air in a contactor. The higher the pressure, the more gas can be dissolved in the water.

However, most units are designed for a contact pressure of 20 to 40 psig. Normally, 20 to 50% of the treated water is recirculated for contact with the gas.

The gas-saturated water is then injected into the flota- tion chamber as shown in Fig. 15.19. The dissolved gas breaks out of solution in small-diameter bubbles when the flow enters the chamber, which is operated at near- atmospheric pressure.

Design parameters are recommended by the individual manufacturers but normally range from 0.2 to 0.5 scfibbl of water to be treated and flow rates of treated plus recycled water of between 2 and 4 gal/(min-sq ft). Retention times of 10 to 40 minutes and depths of be- tween 6 and 9 ft are specified.

Dissolved-gas units have been used successfully in refinery operations where air can be used as the gas and where large areas are available. In treating produced water for injection, it is desirable to use natural gas to ex- clude oxygen. This requires the venting of the gas or in- stallation of a vapor recovery unit. Field experience with dissolved-natural-gas units have not been as successful as experience with dispersed-gas units.

Dispersed-Gas Units. In dispersed-gas units, gas bub- bles are dispersed in the total stream either by use of an inductor device or by a vortex set up by mechanical rotors. Fig. 15.20 shows a schematic cross section of such a unit.

Most dispersed-gas units contain three or four cells. Bulk water flow moves in series from one cell to the other by underflow baffles. Field tests have indicated that the high intensity of mixing in each cell creates the effect of plug flow of the bulk water from one cell to the next. That is, there is virtually no short circuiting or breakthrough of a part of the inlet flow to the outlet weir box.

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15-28 PETROLEUM ENGINEERING HANDBOOK

ZONE DESCRIPTION

VAPOR SPACE

AIR OR GAS INDUCTION

FLOTATION

PwOucEo ic:;a INLET

Fig. lS.PO-Dispersed-gas unit with inductor device.

Field tests and theory both indicate that these units operate on a constant percent removal basis. Within nor- mal ranges, their oil removal efficiency is independent of inlet concentration or oil droplet diameter. The design of the induction nozzle or rotor and internal baffles is critical for determining overall efficiency.

Field experiments indicate that most designs can be expected to have efficiencies of about 90%. Because the gas is recycled by the unit, a natural gas blanket can easi- ly be maintained with little or no venting. The low re- quired retention times makes this an ideal choice for off- shore facilities where space and weight are at a premium.

Dissolved Gas Removal

Often, produced or surface waters will contain dissolved gases, which must be removed by the water-treating plant. Oxygen in concentrations of 0.05 ppm in hydrogen-sulfide-free water and 0.01 ppm in water con- taining hydrogen sulfide is generally considered to be sufficient to cause corrosion problems in the facilities and bacteria plugging problems in an injection reservoir. For this reason, attempts are made to exclude oxygen from produced-water systems by maintaining gas blankets on all tanks. However, sometimes these

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systems must be designed to handle rainwater, which may introduce dissolved oxygen in sufficient quantities to require removal. The location of surface water intakes can be arranged to minimize the oxygen content in the surface water but, in almost all cases, oxygen may have to be removed.

Some waters may contain ammonia, HZS, or COz, which must be removed. Dissolved gases are commonly removed by either chemical scavenging, gas stripping, or liquid extraction. It is beyond the scope of this book to deal with the design of the complex processes and equip- ment that can be employed in removing all dissolved gases. Since oxygen is the most common contaminant, we will briefly describe the treatment processes com- monly in use to remove dissolved oxygen.

Oxygen Scavengers

Chemical scavengers are used quite often to remove dissolved oxygen from water streams of less than 10,000 B/D. Sulfite is the most common scavenging agent for water treating. The most common forms are sodium sulfite, sodium bisulfite, ammonium bisulfite, and sulfur dioxide. To speed the reaction rate, a catalyst such as cobalt is required.

Gas Stripping

The basic principle employed in gas stripping is that the quantity of oxygen dissolved in the water is directly pro- portional to the partial pressure of the gas that is in con- tact with the water (Henry’s law). Since partial pressure of the gas is a function of the mole fraction of that gas, the addition of other gases to the solution will decrease the partial pressure of oxygen and thus the concentration of oxygen in the water.

In a typical gas stripping column, natural gas or steam, if available, is introduced in the base of a packed or trayed column (similar to the familiar glycol contactor used in gas dehydration) and flows upward countercur- rent to the water, which is introduced in the top of the column and flows downward.

If natural gas is used, the oxygen-contaminated gas from the top of the tower can be used for fuel, com- pressed for inclusion in the sales gas stream, or vented, depending on the process design and gas sales contract. Stripping gas usage of between 2 and 5 scf/bbl is common.

It is also feasible to strip oxygen from water by use of a concurrent flow. This is common in cases where lift gas is used as the artificial-lift mechanism for obtaining the water from a reservoir or subsea source. Sometimes, the gas is injected into the water with a static mixer in concurrent flow in a pipe. While this may require more stripping gas, it may be more economical from the stand- point of equipment cost, space, and weight when the value of the stripping gas is low. Stripping gas usage in concurrent flow can be in excess of 10 scf/bbl.

Vacuum Deaeration

Since the partial pressure of oxygen in the gas is a func- tion of the total pressure of the system, the partial pressure of oxygen can also be reduced by applying a vacuum to the water-gas system. Vacuum deaemtors can be combined with either counterconcurrent or concurrent

stripping gas to provide very low oxygen concentrations in the water. Stripping gas usages of a fraction of a cubic foot per barrel are common. Vacuum stripping towers are used where no stripping gas is available, the available stripping gas contains contaminants such as CO;! and H2S, and stripping gas has a high value.

Dissolved Solids Removal

The removal of dissolved solids is of major importance if the water is to be used in steam generation or for some EOR projects. In particular, magnesium and calcium ions in the water may cause boiler scale, react adversely with an EOR chemical, or precipitate in the reservoir as a plugging solid.

Various processes have been used to create chemical reactions to cause the dissolved solids to form precipitates, which can then be settled or filtered out of the water. Aeration has been used to oxidize soluble fer- rous compounds to insoluble ferric compounds, and soluble bicarbonates to insoluble carbonates. However, this process introduces dissolved oxygen, which must then be stripped out of the solution.

The addition of chemicals, such as lime and soda ash, under correct conditions of temperatures and pH can form insoluble carbonates. Alum or other coagulants are then added to help in the settling or filtering of the precipitate. The equilibrium constants for these reactions are usually such that the low total dissolved solids (TDS) required cannot be easily met. For this reason, ion ex- change has become the most common process for control of dissolved solids.

Ion exchange can be defined as a reversible exchange of ions between a solid and a liquid in which there is no significant change in the structure of the solid. Ion- exchange solids of various types can be used. The usual ion-exchange material takes the form of granules, or beads, ranging in size from approximately 0.3 to 1 .O mm in diameter.

As a very broad generalization, the synthetic ion- exchange resins can be categorized into four groups.

1. Strong acid resins. These are polystyrene resins that are strongly acid, have a high exchange capacity, and are not damaged by strongly alkaline hot water.

2. Strong base resins. Typical resins in this category incorporate a quatemary ammonium type of structure. The hydrocarbon groups may include methyl groups, polymeric benzyl groups, ethanol groups, and the like.

3. Weak acid resins. These resins usually contain car- boxylic groups as the active, or functional, ion sites. They have a limited use in water treatment, but can be used to remove basic materials from solution.

4. Weak base resins. Typical resins in this category are of the polyamine type. They usually contain a mix- ture of primary, secondary, and tertiary amine groups and their chemical properties are analogous to amine or ammonium hydroxide solutions. They can be used to remove free acids from solution.

Table 15.11 presents general guidelines for the use of different combinations of resins.

In ion-exchange units the influent water flows through the bed of ion-exchange material. Ions from the bed are exchanged for the undesirable ionic species in the water. When a bed is close to breakthrough, it is regenerated

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PETROLEUM ENGINEERING HANDBOOK

TABLE 15.11-GUIDELINES FOR CATALYST SELECTION

Feed

TDS Hardness Resin Process

< 2,000 < 700 strong acid single bed 700 to 5,000 < 2,000 strong acid series bed

5,000 to 10,000 < 500 weak acid single bed 5,000 to 10,000 500 to

2,000 strong to weak

10,000 to 25,000 <2,000 > 25,000 < 500

acid series operation weak acid series bed chelating single bed

with a strong solution of the ionic species originally con- tained in the ion-exchange material. The exit solution from the regeneration stage is thus a concentrated solu- tion of the contaminants removed from the water.

Removing Hydrocarbons From Solids Fortunately, most solids that must be handled in a water treating plant are water-wet. Reservoir sand in its in-situ condition is almost always water-wet. As it flows up the tubing and through the process system, it may become coated with an oil layer but, since this layer is on top of a water-wet solid, it is easily removed. The two most com- mon solids cleaning processes arc abrasion and water washing.

In separating solids with a hydrocyclone, the solids rub against the inside wall of the cone and against each other. The high centrifugal velocities involved abrade the oil layer, cleaning the solid. In most applications, one pass through a hydrocyclone is sufficient to clean the solids sufficiently for disposal. Some installations in- clude two or three cyclones, in series, to ensure adequate cleaning. In some installations, an air flotation step is used between cyclones to separate any oil that may exit through the cyclone underflush.

Another cleaning method involves the routing of the undefflush to a batch cleaning vessel. Water is induced in the vessel to agitate and wash the solids. The solid bed is then allowed to settle while the oil is skimmed from the top. The procedure is repeated several times until the solids are clean enough to be educted from the bottom of the vessel and disposed of as a slurry.

On offshore platforms, skim piles have been used ef- fectively to water wash and abrade solids. The solids move down the pile and are abraded as they bounce along the baffle surfaces. These are water-washed in the mixture around the end of each baffle. Oil removal oc- curs in the normal manner within each baffle section.

Process Selection and Project Management The process selection for a specific project must provide an overall cost-effective system using the individual techniques described previously. In some cases, the process selection and design of the system may be ob- vious and easily handled by hooking up some standard pieces of equipment in the field with no further engineer- ing design. However, in most cases, several alternative schemes may have to be analyzed, and the process will be complex enough to require the system to be engineered to work as designed. Cost may be significant

enough to necessitate competitive bids for equipment and installation.

Every project, no matter how small, must proceed through the following steps. On small projects, the engineer alone may handle some of these steps in a mat- ter of minutes. On larger projects, these may take months of analysis and work by teams of individuals.

Conceptual Studies

The first step of any project, the conceptual study, in- vestigates one or more means of accomplishing the objective. An economic and technical assessment and comparison of the various methods or schemes is made. Block diagrams may be used to develop a selected proc- ess or alternative into specific descriptions and recom- mendations for equipment. Equipment type and arrange- ment are studied and a design philosophy established. An analysis of cost and economic benefit of each alter- native is performed and a recommendation made.

Project Definition

The next phase is to define the project for the scheme selected in the conceptual study. Tools used are process flow sheets, layout drawings, preliminary cost estimate, and project execution plan.

The block diagram is converted into a process flow sheet to better define the project. The flow sheet shows all major equipment, main piping, and operating pressures and temperatures. Instrumentation that con- trols the main process flow is shown and every major line is assigned a stream number. A table is included listing pertinent operating data for these streams.

Layout drawings locate the equipment on the process flow sheets. A well-planned layout is the key to good operation, economical construction, and efficient maintenance. The layout drawing must be integrated with the development of the process flow sheet and must be settled before detailed piping, structural, and elec- trical design can begin.

A plan of execution for a project begins when the first information is received. This plan must consider the alternatives for breaking the job down into individual work items for bid solicitation. It must balance time and ease of management against cost for such decisions as (1) the scope of work to be included in individual work, (2) degree of engineering to perform prior to bid, (3) potential suppliers’ work load, capability, and com- petitive situations, and (4) operator sole source preferences.

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The preliminary cost estimate is an important tool in the generation of the initial authority for expenditure (AFE). For effective cost control, the preliminary estimate must be made accurately and upgraded when in- formation is received that affects it. Revisions may be necessary because of a change in scope or a realization that the amount of work was over- or underestimated.

Design Engineering

Once the need and extent of engineering assistance is determined, design engineering must begin to translate the process flow sheets into specific objectives and to determine activities required to attain these objectives. The basic item on which all other activities depend and which must be completed early in an engineering design project is the mechanical flow sheet.

Mechanical flow sheets are established from the proc- ess flow sheets and show every piece of equipment for the entire facility, including process, utilities, fire-water system, safety systems, spare equipment, etc. Every in- strument, valve, and specialty item is shown schematically. Piping should be shown with flow arrows and line numbers indicating size, pressure rating, heat tracing, and insulation.

Vessel and equipment specifications are established for long-delivery items to expedite both the design and purchasing effort. Every facility is designed for a specific function, and thus the criteria by which the equipment is selected are applicable to that facility only. Therefore, this equipment is not normally produced off- the-shelf items. However, an experienced engineer will maximize the use of standard items to minimize cost and delivery time.

Detail Engineering

Once design engineering is completed and major equip- ment items have been specified and sent out for bid, the next step is to perform the detail engineering. This con- sists of piping drawings, structural drawings, electrical one-line drawings, instrument data sheets, and control schematics.

Piping drawings translate to the fabrication contractor the piping arrangement, as defined in the mechanical flow sheets. In many cases, a good set of piping draw- ings is the key to any easy to build and operate facility. In all cases, a good set of drawings is required to speed installation and keep the cost for extras to a minimum.

Structural drawings for an onshore facility detail the foundation site development and road work required, as well as detailing any pipe supports or skids for the pro- duction equipment. For an offshore facility, these draw- ings can include platform drawings as well as those for production skids themselves. The skids could be in- stalled on wooden or concrete piles, steel or concrete barges, or steel jackets with steel decks.

Procurement

A large part of the engineen’ng effort is involved in bid- ding, evaluating, expediting, and coordinating vendors and vendor information. This is true whether the work is performed by the operator, the engineering consultant, or a turnkey contractor.

Special, long-delivery equipment, vessels, and in- strumentation usually are ordered as soon as the

specification can be written, checked, bids obtained and evaluated, and the purchase order issued.

All bids should be opened at one time to minimize any possibility of a bidder receiving an unfair advantage. While it is possible to play one bidder against another by “bid shopping,” any experienced project engineer knows that in the long run this will be counterproductive. If vendors expect the work to be given to the low bidder, they will put their best effort into the price. If an auction is expected, the bid price will reflect this.

Inspection and Expediting

An important phase of the project is inspection. It is the inspector’s responsibility to ensure that the finished equipment or material is of acceptable quality and com- plies with all requirements of the purchase order.

The inspector witnesses tests on mechanical equip- ment such as pumps and compressors, observes and ap- proves fabrication methods of vessels, pipe, and struc- tural steel, and generally ensures that the best workman- ship is being performed on the purchased equipment.

The purchaser’s expediter can do much to ensure that the estimated delivery dates will be met by working with both the manufacturer and his own organization. The ex- pediter should seek and study all information that might affect delivery, anticipate delays or bottlenecks, and resolves these with the vendor. He should assist the ven- dor in obtaining priorities and solving procurement prob- lems by communicating with subsuppliers. If delivery schedules must change, he should advise his employer as early as possible. On small projects, these functions are performed by the inspectors.

Startup

The conscientious preparation of a startup and operations procedure is the best possible check of the practicability, operability, and safety of a system. The procedure may contain only a few pages or may take the form of a book. In any case, it describes (1) overall purpose and design of the installation, (2) operation of the process, (3) details and operating descriptions of all systems, in- cluding overall instrumentation (pneumatic and/or elec- tronic) electrical, data transmission, utility and fire- water, etc., (4) instructions for equipment installation, (5) purge and preparation for operation, and (6) pro- cedure for starting.

Project Execution Format

Every project goes through the steps of project manage- ment described above. This is true no matter whether the tasks are performed by the operator’s staff, the engineer- ing consultant, or contractors. The project must progress from one step to the next; engineering, procurement, and inspection must be accomplished; and the cost of per- forming these functions must be borne by the project.

There arc several different project execution formats that must be considered. The choice of a specific format will determine which of these functions will be per- formed by a particular organization.

Although there are almost as many formats as there are projects, most can be separated into the following four basic types which we shall call turnkey, negotiated tum- key, modified turnkey, and cost plus.

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Turnkey. The turnkey format is used when the work is not completely designed. The conceptual study and proj- ect definition are normally complete. In this case, the scope of the contractor’s work would include the design engineering, detail engineering, procurement, inspection and expediting, and possibly, startup.

Five advantages are claimed by proponents of this for- mat: (1) the project cost is established before work starts, (2) a single point of responsibility is established, (3) the contractor can design to take advantage of constmction efficiencies, (4) the contractor can speed up equipment delivery by performing engineering in such a manner as to get long lead time equipment on order sooner, and (5) the contractor assumes risk.

Several problems have been experienced with this format.

1. Owner loses design control or can exercise it only at high cost in extra work.

2. Competition is limited to select firms with total design and construction capability.

3. Most large firms have different engineering and construction profit centers. Many large contractors bid the work to outside engineering firms. In either case, the contractor’s engineers may be no more or less aware of construction efficiencies than a third party.

4. Because of the design risks assumed by the contrac- tor, a contingency factor will be added to the price.

5. By necessity, there will be a large number of sub- contractors furnishing individual items of equipment to the turnkey contractor. Other than initial approval, the owner has no control over subcontractors.

6. The contractor’s and owner’s interests are not iden- tical. The contractor has an incentive to provide the least costly quality for the fixed price and does not profit or lose nearly as much as the owner with timely delivery. Therefore, the owner must provide inspection and ex- pediting. It is very difficult to do this for subcontractors where no direct commercial relationship exists.

Negotiated Turnkey. The negotiated turnkey format recognizes that, before the detail engineering is com- plete, it is difficult for a contractor to provide a fixed price for the work while maintaining adequate owner control. In this format, the design and detail engineering are performed (normally for a fixed fee), so that long- delivery items can be placed on order prior to completion of detail engineering. Once the scope of work is defined, a turnkey price is negotiated.

The advantages claimed for this format are the same as those for the turnkey format with the added advantages of maintaining owner control and reducing contractor’s design risk. The disadvantages are identical with the added disadvantage of eliminating much of the owner’s leverage when it comes to negotiating the final contract.

Modified Turnkey. In the modified turnkey format, each work item is separated and bid turnkey as the scope of that work item is defined. In the previous two formats, the prime contractor does this in bidding out items of equipment to subcontractors. The difference in this for- mat is that the owner, or engineering consultant, do the bidding, awarding, and expediting. In addition, those items which are “sole sourced” to the contractors con- struction arm in the two previous formats must be bid

and evaluated. The main advantages claimed for this for- mat are (1) control of the project is maintained, (2) com- petition is maximized as individual work items can be bid to firms specializing in such work, (3) owner’s in- spectors and expediters have a direct commercial rela- tionship to all suppliers, and (4) contractor’s risk and contingency is controlled to the extent desired by owner. For example, scope of work contingency can be eliminated while weather contingencies are included.

The disadvantages with this format are (1) increased coordination of the contracts is required by either the owner or the engineering consultant, (2) the owner, or consultant, must develop and monitor the plan of execu- tion rather than this being a function of the turnkey con- tractor, and (3) engineering and project management costs are explicitly determined and not hidden in contract cost.

Cost Plus. The cost-plus format requires the contractor to be reimbursed for all direct costs plus a percentage of costs for overhead and profit. Typically, this format is used where risk is high, or when there is insufficient time to solicit firm bids. Such a case would occur if construc- tion were required within an operating plant, it were necessary to repair storm damage, or a simple field routing job were envisioned. The major disadvantage of this format is that the owner bears the risk of inefficient labor and job organization.

Comparison of Formats. The type of project format to employ depends on the nature of the project, the type of contractors available and their competitive position, and the priorities of the owner. There is no one answer as each project is different and competition and priorities change from time to time.

The author had the opportunity to be involved in two similar projects for the same owner, which occurred almost simultaneously. One was set up as a turnkey for- mat and the other in a modified turnkey format to test the validity of the claimed advantages and disadvantages. The cost of the modified turnkey approach was 15% less, and it took 10% less time to complete because of greater owner control of the schedule. On another recent project, the design was done by the owner and each work item bid out separately. In addition, two turnkey bids were solicited from companies who expressed a desire to construct the complete installation. The additional cost for awarding the low turnkey bid would have been 40% more than the cost of awarding 10 individual bids.

Project Control No matter what the project execution format, it is necessary to implement procedures for controlling both project cost and timing. The most important part of proj- ect control begins at the outset of the project with con- trolling the engineering effort. Priorities set and deci- sions made at this point will affect project timing and cost throughout the job.

An activities schedule will help in project scheduling. This is a detailed plan of execution for the project’s engineering phase and is similar to, but more detailed than, the overall project plan of execution described previously. When preparing the activities list, an effort should be made to separate activities into logical cost categories.

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The main tool for project cost control is the preliminary cost estimate developed during project definition, which lists budget costs for each item in the plan of execution. Budgets should be established for scheduled work packages. It is important for cost control purposes that activities have definite starting and ending points.

Costs are periodically updated as the project becomes better defined. Differences can then be explained and total project cost revised-even before the first item is purchased. As bids are awarded and commitments are made, the total project amount can be adjusted accordingly.

Accounting for costs can be routine, but controlling costs is another matter. Once a project is committed, a large part of final cost is beyond control of the project engineer. It is not unusual for bid items to vary significantly from time to time because of contractor work load, weather conditions, and availability of equip- ment. Also, difference in price between low bidder and next low bidder can vary 10 to 20%. If the low bidder had not been included in the bid list, item cost would be that much higher. On a recent project, the sum of second low bidders’ prices was 5% higher than that of low bidders.

Early in the project, timing is controlled through the engineering effort to ensure that bids are sent out, evaluated, and awarded in accordance with the project plan of execution. Once bids are awarded, the inspector and/or expediter are responsible for determining if work is progressing on schedule. A schedule thus must be worked out with the successful bidder, preferably before bid award. When delays are spotted, meetings with the contractor are required to return the job to schedule. On occasion, it may be necessary to appeal to higher levels of management in both companies. The sooner a pmb- lem is spotted, the better the chance that corrective ac- tion can be agreed on. On large complex projects. the use of computer-based network analysis of activities is sometimes beneficial.

Nomenclature

A, = area of deck, sq ft b = width (breadth), fi

b, = width (breadth) of the plate section perpendicular to the axis of water flow, ft

Cd = dispersion constant CE = constant for erosional flow

C’eW = constant with a value of 80 to 140, de- pending on the inside pipe material and its age

dd = oil droplet diameter, micrometers

(dd)max = maximum oil droplet diameter, micrometers

di = pipe inside diameter, in. dp = particle diameter, microns

E = flow efficiency, fraction E, = pump efficiency at flow conditions E,, = removal efficiency on any cycle of a

particular drop size E,, = overall particle removal efficiency

f= fv =

F=

friction factor volume fraction of the dispersed phase factor to account for turbulence and short

circuiting hf = height of flume, ft

K,s = empirical settling constant L= length of line or length of plate section

L, = L2 =

Lb.\ = L, = L, = N,. =

parallel to the axis of water flow, ft inlet distribution section outlet gathering section length of baffle section, ft effective settling section perpendicular distance between plates, in. number of cycles of no flow a particle

NR, =

Phh =

PI =

P? = 48 =

sees as it traverses the baffle section Reynolds number brake horsepower pressure at pipe inlet, psia pressure at pipe outlet, psia flow rate of gas at standard conditions,

MMscfiD

qL =

qr =

qH. = t=

t, =

t, =

t.7 =

t M’ =

VRf =

liquid flow rate, B/D rainfall rate, in./hr bulk water flow rate. BWPD time for the dump cycle, seconds time valve is closed, seconds retention time, minutes time particle is falling while in effective

section of flume time water is in effective section of

flume velocity of gas at specific flow

conditions, ft/sec v s = settling velocity, ft/sec

Zf/ = friction head loss, ft of liquid Z, = height of the coalescer plate section

perpendicular to the axis of water flow, ft

Z, = height of water column, ft

-fR = specific gravity of the gas at standard conditions relative to air

ye = specific gravity of liquid relative to water Ay = difference in specific gravity relative to

water

AY ow = difference in specific gravity between oil and water

8 = angle of the plate with the horizontal pLnf = viscosity of gas at specific flow

conditions, cp

References 1. Daughelty, R.L. and Ingersoll, A.C.: Fluid Mechanics with

Engineering Applications, McGraw-Hill Book Co. Inc., New York City (I 954) 205.

2. “Flow of Fluids Through Valves, Fittings and Pipe,” Crane Co., Houston (1969) Technical Paper 410, l-8.

3. Design and Insrallation of QJshore Production Platform Piping Systems, third edition, API RPl4E, API, Dallas (1981) 22.

4. API Specification for Polyethylene Line Pipe (PE), third edition, API Spec. 5LE, API, Dallas (Nov. 1981).

5. API SpeciJcation for Thermoplastic Line Pipe (PVC and CPVC), fifth edition, API Spec. 5LP, API, Dallas (Nov. 1981).

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15-34 PETROLEUM ENGINEERING HANDBOOK

6. API Specification for Reinforced Thermoserring Resin Line Pipe (RTRP), fourth edition, API Spec. 5LR, API, Dallas (March 1976).

I. API Specification for Line Pipe, 33rd edition, API Spec. 5L. API, Dallas (March 1983).

8. Recommended Practice for Application of Cement Lining to Steel Tubular Goods, Handling Installation and Joining (Tentative), first edition, API RP IOE, API, Dallas (March 19%).

9. American National Code for Pressure Piping, Power Piping, ANSI B31.1, American Sk. of MechanicalEn&eers, New’York City (1977).

10. ASME Code for Pressure Piping, B31, Chemical Plant and Petroleum ReJinety Piping, ANSIIASME 831.3, American Sot. of Mechanical Engineers, New York City (1980).

1 I. American National Standard Code for Pressure Piping, Liquid Petroleum Transportation Piping System, ANSIIASME B3 1.4,

American Sot. of Mechanical Engineers, New York City (1979). 12. American National Standard Code for Pressure Piping, Gas

Transmission and Distribution Piping Systems, ANSI B3 1.8, American Sot. of Mechanical Engineen, New York City (1975).

13. American National Standard, Pipe Flanges and Flanged Fittings I ANSI B16.5, American Sot. of Mechanical Engineers, New York City (1981).

14. API Specifications for Wellhead Equipment, 14th edition, API Spec. 6A, API, Dallas (March 1983).

15. “Oil-Water Separator Process Design,” Manual on Disposal of Refinery Wastes, Volume on Liquid Wastes. API, Dallas (1975) Chapter 5.

16. Brunsmann, J.J., Comelissen, J., and Eilen, H.: “Improved Oil Separation in Gravity Separators,” paper presented to the 1959 API Committee on Disposal of Refinery Wastes, Denver, Oct. 14-16.