In 1855 it was found that distillation of petroleum pro- duced a light oil that was similar to coal oil and better

than whale oil as an illuminant. This knowledge

spurred the search for saline waters that contained oil.

saturation resulted from the action of an unsuspected flood. the existence of which was not known when the

location for the test well had been selected. The upper

part of the sand was not cored. Toward the end of the

a cable tool core barrel. oil ole so fast that it was not

the cutting of the second sec-

the lower 3 ft of the Bradford

hole free from water. Two

ere preserved in sealed con-

, and both of them, when

tent of about 2O%PV. This

and no water after being shot he evidence developed by the

ctivity test after completion

ation of the existence of im- Using the methods of the salt producers, Col. Edward Drake drilled a well on Oil Creek, near Titusville. PA. in

1859, He struck oil at a depth of 70 ft, and this first oil

well produced about 3.5 B/D.

The early oil producers did not realize the significance

of the oil and saline waters occurring together. In fact, it

was not until 1938 that the existence of interstitial water

in oil reservoirs was generally recognized. 4 Torrey was

convinced as early as 1928 that dispersed interstitial water existed in oil reservoirs, but his belief was rejected

by his colleagues because most of the producing wells

cutting of the first core withbegan to come into the h

necessary to add water for

tion of the sand. Therefore,

sand was cut with oil in a

samples from this section w

tainers for saturation tests

analyzed, had a water con

well made about IO BOPD with nitroglycerine. Thus, t

core analysis and the produ

provided a satisfactory indicChapter 24

Properties of ProducedA. Gene Collins,* U S. DOE Bartlesville Energy Technology Ce

Introduction and History Early U.S. settlements commonly were located close to salt licks that supplied salt to the population. Often these

salt springs were contaminated with petroleum. and

many of the early efforts to acquire salt by digging wells

were rewarded by finding unwanted increased amounts

of oil and gas associated with the saline waters. In the

Appalachian Mts.. many saline water springs occurred

along the crests of anticlines. did not produce any water upon completion. Occur-

rences of mixtures of oil and gas with water were recognized by Griswold and Munn,6 but they believed

that there was a definite separation of the oil and water,

and that oil, gas, and water mixtures did not occur in the

sand before a well tapped the reservoir.

It was not until 1928 that the first commercial laboratory for the analysis of rock cores was established,

and the first core tested was from the Bradford third sand

(from the Bradford field. McKcan County. PA). The

Now with the Natl Ins1 of Petroleum and Energy Research Eartlesv~lle OK

The author of the or!gmal chapter on this topic I the 1962 edlllon was J Wade W2fk,< Waters nter**

percent saturation and percent porosity of this core were

plotted vs. depth to construct a graphic representation of

the oil and water saturation. The soluble mineral salts

that were extracted from the core led Torrey to suspect

that water was indigenous to the oil-productive sand.

Shortly thereafter a test well was drilled near Custer Ci-

ty, PA, that encountered higher than average oil satura-

tion in the lower part of the Bradford sand. This high oil mobile water, indigenous to the Bradford sand oil reser-

voir, which was held in its pore system and could not be

produced by conventional pumping methods.

Fettke was the first to report the presence of water in

an oil-producing sand. However, he thought that it might

have been introduced by the drilling process.

Munn* recognized that moving underground water might be the primary cause of migration and accumula-

tion of oil and gas. However, this theory had little ex-

perimental data to back it until Mills conducted several

laboratory experiments on the effect of moving water and gas on water/oil/gas/sand and water/oil/sand

systems. Mills concluded that the up-dip migration of

24-2

oil and gas under the propulsive force of their buoyancy

in water, as well as the migration of oil, either up or

down dip, caused by hydraulic currents, are among the

primary factors influencing both the accumulation and the recovery of oil and gas. This theory was seriously

questioned and completely rejected by many of his contemporaries.

Rich I assumed that hydraulic currents, rather than

buoyancy, are effective in causing accumulation of oil or

its retention. He did not believe that the hydraulic ac-

cumulation and flushing of oil required a rapid move-

ment of water but rather that the oil was an integral con-

stituent of the rock fluids and that it could be carried

along with them whether the movement was very slow or

relatively rapid.

The effect of water displacing oil during production

was not recognized in the early days of the petroleum in

dustty in Pennsylvania. Laws were passed, however, to

prevent operators from injecting water into the oil reser-

voir sands through unplugged wells. In spite of these

laws, some operators at Bradford secretly opened the

well casing opposite shallow groundwater sands to start a watertlood in the oil sands. Effect of artificial

watertloods were noted in the Bradford field in 1907,

and became evident about 5 years later in the nearby oil

fields of New York. Volumetric calculations of the

oil-reservoir volume that were made for engineering

studies of these waterflood operations proved that in-

terstitial water was generally present in the oil sands.

Garrison and Schilthuis gave detailed information

concerning the distribution of water and oil in porous

rocks, and of the origin and occurrence of connate

water with information concerning the relationship of

water saturation to formation permeability.

The word connate was first used by Lane and Gor-

don to mean interstitial water that was deposited with

the sediments. The processes of rock compaction and

mineral diagenesis result in the expulsion of large

amounts of water from sediments and movement out of

the deposit through the more permeable rocks. It is

therefore highly unlikely that the water now in any pore

is the same as that which was there when the particles

that surround it were deposited. White redefined con- nate water as fossil water because it has been out of

contact with the atmosphere for an appreciable part of a

gcnlogic time period. Thus. connate water is distin-

cruished from meteoric 2 water, which has entered the

rocks in geologically recent times, and from juvenile

water. which has come from deep in the earths crust and

has never been in contact with the atmosphere.

Meanwhile. petroleum engineers and geologists had

learned that waters associated with petroleum could be

identified with regard to the reservoir in which they oc-

curred by a knowledge of their chemical characteristics.

Commonlv, the waters from different strata differ con- siderably In their dissolved chemical constituents. mak-

ing the identification of a water from a particular stratutn

easy. Howjcvcr. in some areas the concentrations of

dissolved constituents in waters from different strata do not ditfcr significantly, and the identification of such

waters is difficult or impossible. The amount of water produced with the oil often in-

creases as the amount of oil produced decreases. lfthis is edge water. nothing can be done about it. If it is botton- PETROLEUM ENGINEERING HANDBOOK

water, the well can be plugged back. However, it often is

intrusive water from a shallow sand gaining access to the

well from a leaky casing or faulty completion and this can be repaired.

Enormous quantities of water are produced with the oil

in some fields, and it is necessary to separate the oil from

the water. Most of the oil can be removed by settling.

Often, however, an oil-in-water emulsion forms, which

is very difficult to break. In such cases, the oil is heated

and various surface-active chemicals are added to induce

separation.

In the early days, the water was dumped on the

ground, where it seeped below the land surface. Until

about 1930, the oilfield waters were disposed into local

drainage, frequently killing fish and even surface vegeta-

tion. After 1930, it became common practice to

evaporate the water in earthen pits or inject it into the

producing sand or another deep aquifer. The primary

concern in such disposal practice is to remove all oil and

basic sediment from the waters before pumping them in- to injection wells to prevent clogging of the pore spaces

in the formation receiving the waste water. Chemical

compatibility of waste water and host aquifer water also

must be ensured.

Waters produced with petroleum are growing in im-

portance. In years past, these waters were considered

waste and had to be disposed of in some manner. Injec-

tion of these waters into the petroleum reservoir rock serves three purposes: it produces additional petroleum

(secondary recovery), it utilizes a potential pollutant.

and in some areas it controls land subsidence.

The volume of water produced with petroleum in the U.S. is large. In 1981 domestic oil production was about

8.6~ IO B/D and the amount of water produced with

the oil ranges from 4 to 5 times the oil production.

Therefore, the water production, assuming a factor of 4.5, would be about 38.7~ IO BID.

Secondary and tertiary oil recovery processes that use

water injection usually result in the production of even

more water along with the oil. To inject these waters into

reservoir rocks, suspended solids and oil must be re-

moved from the waters to prevent plugging of the porous

formations. Water injection systems require xepardtors,

filters, and, in some areas, deoxygenating and bacteria

control equipment with chemical and physical methods

to minimize corrosion and plugging in the injection

system.

In waterflooding most petroleum reservoirs, the volume of produced water is not sufficient to rccovcr the

additional petroleum efficiently. Therefore, supplemen-

tal water must be added to the petroleum reservoir. The

use of waters from the other sources requires that the

blending of produced water with supplemental water

must yield a chemically stable mixture so that plugging

solids will not be formed. For example, a produced

water containing considerable calcium should not be

mixed with a water containing considerable carbonate

because calcium carbonate may precipitate and prevent

injection of the tloodwater. The design and successful

operation of a secondary or tertiary recovery operation requires a thorough knowledge of the composition of the waters used.

Chemical analyses of waters produced with oil are

useful in oil production problems. such as identifying the

PROPERTIES OF PRODUCED WATERS

source of Intrusive water, planning watcrfood and

saltwater disposal projects. and treating to prevent corro-

sion problems in primary, secondary, and tertiary

recovery. Electrical well-lo g interpretation rcquircs a

knowlc$Fc of the dissolved solids concentration and

composltton of the interstitial water. Such information

also is useful in correlation of stratigraphic units and of

the aquifers within these units. and in studies of the movcmcnt of xubsurfacc waters. It is impossible to

understand the processes that accumulate petroleum or

other minerals without insight into the nature of these

waters.

Sampling The composition of subsurface water commonly changes

with depth and also laterally in the same aquifer. Changes may be brought about by the intrusion of other

waters. and by discharge from and recharge to the

aquifer. It is thus difficult to obtain a representative sari--

pie of a given subsurface body of water. Any one sample is a very small part of the total mass. which may vary

MJidely in composition. Therefore. it is generally

necessary to obtain and analyze many samples. Also. the

samples may change with time as gases come out of

solution and supersaturated solutions approach

saturation.

The sampling sites should be selected, if possible, to

fit into a comprehensive network to cover an oil-

productive geologic basin.

There is a tendency for some oilfield waters to become more diluted as the oil reservoir is produced. Such dilu-

tion may result from the movement of dilute water from

adjacent compacting clay beds into the petroleum rescr-

voir as pressure declines with the continued removal of

oil and brine.

The composition of oilfield water varies with the posi-

tion within the geologic structure from which it is ob-

tained. In some cases the salinity will increase upstruc-

ture to a maximum at the point of oil/water contact.

Few of the samples collected by drillstem test (DST)

arc truly representative formation-water samples. During

drilling. the pressure in the wellbore is intentionally maintained higher than that in the formations. Filtrate

from the drilling mud seeps into the permeable strata.

and this filtrate is the first liquid to enter the test tool.

The most truly representative formation-water sample

usually is obtained after the oil well has produced for a period of time and all extraneous fluids adjacent to the

wellhore have been flushed out. Samples taken im-

mediately after the well is completed may be con- taminated with drilling fluids and/or with well complc-

tion fluids. such as filtrate from cement, tracing fluids,

and acids. which contain many different chemicals.

Sampling methods are discussed in publications of the American Petroleum Inst. (API), American Sot. for

Testing and Materials (ASTM), and the Natl. Assn. of

Corrosion Engineers (NACE). I8

Drillstem Test

The DST, if properly made, can provide a reliable for-

mation water sample. it is best to sample the water after each stand of pipe is removed. Normally, the total

dissolved solids (TDS) content will increase downward

and become constant when pure formation water is ob- 24.3

tained. A test that ilows water will give even higher

assurance of an uncontaminated sample. If only one DST

water sample is taken for analysis. it should bc taken just

above the tool. since this is the last water to enter the tool

and is least likely to show contamination.

Analyses of water obtained from a DST of Smackovcr limestone water in Rains County. TX. show how errors

can be caused by improper sampling of DST water.

Analyses of top, middle. and bottom samples taken from

a SO-ft fluid recovery show an increase in salinity with

depth in the drillpipe. indicating that the first water wa\

contaminated by mud filtrate. I) Thus. the bottom sam-

ple was the most representative of Smackovcr water.

Sample Procedure

No single procedure is universally applicable for obtain-

ing a sample of oilfield water. For cxamplc. inthrmation

may bc desired concerning the dissolved gas or

hydrocarbons in the water or the reduced species present.

such as ferrous or manganous compounds. Sampling

procedures applicable to the desired infomlation must be

used.

Some of the special information and sample location

cases, with appropriate procedures or references cited for

proper sampling. follow.

Sample Containing Dissolved Gas. Knowlcdgc of ccr- tain dissolved hydrocarbon gases is used in

exploration. OZ

Sampling at the Flowline. Another method of obtaining a sample for analysis of dissolved gases is to place a

sampling device in a flowline. Fig. 24. I illustrates such

a device. The device is connected to the flowline. and water is allowed to flow into and through the container.

which is held above the flowlinc. until 10 or more

volumes of water have flowed through. The lower valve

on the sample container is closed and the container removed. If any bubbles are present in the sample, the

sample is discarded and a new one is obtained.

Sampling at the Wellhead. It is common practice in the oil industry to obtain a sample of formation water from a

sampling valve at the wellhead. A plastic or rubber tube

can be used to transfer the sample from the sample valve

into the container (usually plastic). The source and sam-

ple container should be flushed to remove any foreign

material before a sample is taken. After flushing the

system. the end of the tube is placed in the bottom of the

container, and several volumes of fluid are displaced bcforc the tube is removed slowly from the container and

the container is sealed. Fig. 24.2 illustrates a method of

obtalnmg a sample at the wellhead. An extension of this

method is to place the sample container in a larger con- tainer. insert the tube to the bottom of the sample con-

tainer. allow the brine to overflow both containers. and

withdraw the tube and cap the sample under the fluid.

At pumping wellheads the brine will surge out in heads

and be mixed with oil. In such situations a larger con-

tainer equipped with a valve at the bottom can be used as

a surge tank or an oil-water separator or both. To use this

device, place the sample tube in the bottom of the large

container, open the wcllhead valve, rinse the large con- tainer with the well fluid, allow the large container to

24-4

Valve

74

Sample

I-+

container

Fig. 24-l-Flowline sampler.

fill, and withdraw a sample through the valve at the bot-

tom of the large container. This method will serve to ob- tain samples that are relatively oil-free.

Field Filtered Sample. In some studies it is necessary to obtain a field filtered sample. The filtering system shown

in Fig. 24.3 was designed and has proved successful for

various applications. Fig. 24.2-Example of the method used for obtaining a sample at the wellhead. PETROLEUM ENGINEERING HANDBOOK

This filtering system is simple and economical. It con-

sists of a SO-mL disposable syringe, two check valves.

and an inline-disk-filter holder. The filter holder takes

size 47-mm diameter, 0.45pm pore size filters, with the

option of a prefilter and depth prefilter.

After the oilfield brine is separated from the oil, the

brine is drawn from the separator into the syringe. With

the syringe, it is forced through the filter into the collec-

tion bottle. The check valves allow the syringe to be used

as a pump for filling the collection bottle. If the filter becomes clogged, it can be replaced in a few minutes.

About 2 minutes are required to collect 250 mL of sam-

ple. Usually two samples are taken, with the one being

acidified to pH 3 or less with concentrated HCI or HN03. The system can be cleaned easily or flushed with

brine to prevent contamination.

Sample for Stable-Isotope Analysis. Stable isotopes have been used in several research studies to determine

the origin of oilfield brines. 22-24

Sample for Determining Unstable Properties or Species. A mobile analyzer was designed to measure pH, Eh (redox potential), Oz, resistivity, S=, HCOT,

CO,, and CO2 in oilfield water at the wellhead. When

oilfield brine samples are collected in the field and

transported to the laboratory for analysis, many of the

unstable constituents change in concentration. The

amount of change depends on the sampling method,

sample storage, ambient conditions, and the amounts of the constituents in the original sample. Therefore an

analysis of the brine at the wellhead is necessary to ob- tain reliable data.

Sample Containers. Containers that are used include polyethylene, other plastics, hard rubber, metal cans,

and borosilicate glass. Glass will adsorb various ions

such as iron and manganese, and may contribute boron

or silica to the aqueous sample. Plastic and hard rubber

containers are not suitable if the sample is to be analyzed

to determine its organic content. A metal container is

used by some laboratories if the sample is to be analyzed for dissolved hydrocarbons such as benzene.

The type of container selected depends on the planned

use of the analytical data. Probably the more satisfactory

container, if the sample is to be stored for some time Fig. 24.3-Example of field filtering equipment.

24-5

FOR EACH OILFIELD WATER SAMPLE

Field

NwBBPr

dn

sa

relatively high amounts of metal contributed by catalysts Produced Injection Generation Disposal

in their manufacture. The approximate metal content of

the plastic can bc determined by a qualitative emission

spectrographic technique. If the sample is transported

during freezing temperatures, the plastic container is less

likely to break than is glass.

Tabulation of Sample Description. Information such as that in Table 24.1 should be obtained for each sample of

oilfield water.

Analysis Methods for Oilfield Waters Analytical methods for analyzing oilfield waters are im-

proving with respect to precision, accuracy, and speed.

There have been at least two groups trying to standardize

methods of oilfield water analysis during the past 20

years. They are the API and ASTM. The API published

Recommended Practice 45 for Analysis of Oilfield

Waters.

The ASTMs Committee D-19 standardizes methods of analyzing oilficld brines. Methods standardized by

rigorous round-robin testing by several laboratories and

subsequent ASTM committee balloting procedures are

found in Ref. 17. Table 24.2 illustrates the analyses for various proper-

ties or constituents of oilfield water. Methods to deter-

mine most of these properties or constltucnts can bc

found in Refs. 16, 17, and 25 through 30.

Chemical Properties of Oilfield Waters

Water Water Water Water

PH Eh Speciilc resistwty

Speciitc gravity Bacteria

Barium Bicarbonate Boron

Bromide Calcium Carbonate

Carbon dioxide Chlonde

Hydrogen sulfide Iodine IlOll

Magnesium Manganese

Oxygen Potassium

Residual hydrocarbons Sodium Silica Strontium Sulfate Suspended solIds Total dissolved solids

X = usually requesm O=somellmes requested

X

0 X X

0

X

:: 0 X

:: X

0 0 X

::

0 0

X

0 0 X

X

X

X

X

X

; X

X

:: 0

X

:: X 0 PROPERTIES OF PRODUCED WATERS

TABLE 24.1-DESCRIPTION NEEDED

Sample Number Farm or lease ~ of Section Townshlp County State Operators address (main office) Sample obtained by Address Sample obtained from (lead line, separatory flow tank, etc.)

Completion date of well Name of productive zone from which sample is produced Sand Shale Name of productive formation Depths: Top of formation

Top of producing zone Top of depth drilled

Bottomhole pressure and date of pressure Bottomhole temperature Date of last workover Are any chemicals aWell production Initial PreseOil, BID Water, B/D Gas, cu ft/D

Remarks: (such as casing leaks, communication or other pay in

before analysis. is the polyethylene bottle. Not all

polyethylenes are satisfactory because some contain Oilfield waters are analyzed for various chemical and

physical properties. Most oilfield waters contain a varie-

ty of dissolved inorganic and organic compounds. Well No. ~ in the Range

Operator

Date Representing

Lime Other ames of formations ell passes through ottom of formation ottom of producing zone esent depth

ded to treat well If yes, what? t Casing service record,

Method of production (primary, secondary, or tertiary)

me well, lease or field)

TABLE 24.2-GEOCHEMICAL WATER ANALYSES*

Steam

51,200 10,200 60,700 2,330

However.

few of

because money p

propertie

for rcinje

oilfield w

Compos

The com

dilute wawater an

Tables 2

duced wa

1962 edi

The ta

lihted alpareas of t

the smal

or gcosy

ble.

nce

t in-

on.

ses

bles

rces

first

er-

gic

the Ap- 10 Upper Devonian

12 Mississippian

Pennsylvania3 38

IO Devonian

7 Devono- Mississippian

12 Devontan

West Virginia39

29 Mtssisstppian

6 Mississippian

21 Mississippian

44 Pennsylvanian

43 Devonian

First Water Big Lime Berea

5,175 to 5,300

401 to 1,592

Bradford

Venango

Bradford III

-

-

-

Big lnjun 1,390 to 3,215

Squaw 1,908 to 2,019

Maxton 1,287 to 3,259

Salt Sand 450 to 1,960

Oriskany 3,036 to 8,089

25,900 4.100 21.600 29,600 1O;OOO 861400 4,600 1,500 25,000

11,900 3,000 43,900

40 30 1,600 - 32,400 1,940 39,500 - 7,000 70 3,600 -

82,000 2,020 16,000 - 420 40 300 -

16,900 2,530 39,200 -

30 300 50 1,730 3,910 52,200

630 200 6,300 8,920 2,250 38,100

100 40 3,800 15,300 2,740 35,100

400 340 2,500 20,600 2,650 50,900 2,500 480 34,000

33,600 3,800 98,300

270 2,370

120 220

IO 750 290 340 30

660

3,6:: 200

6,900

oil producers usually are interested in only a

the macro properties. This is understandable

oil producers wish to spend the least amount of ossible. Therefore, they will look at only the

s that are necessary to evaluate any treatment

ction to recover more oil or to dispose of the

aters.

ition of Oilfield Waters , ,,

position ot otltteld waters varies from relatively

ters to heavy brines. Several thousand oilfield

alyses are available on computerized files.

4.3 through 24. I4 show characteristics of pro

ters. and much of the text was taken from the

tion of this book.

bulated data on water analyses following arc

basin, a large area not generally otherwise identifia

This division has been made arbitrarily for convenie

and because of the lack of a uniform system and is no

tended as a precedent for any system of classificati

The states or provinces from which reliable analy

were available are listed alphabetically in the ta

under each area.

The reader is referred to the original indicated sou

of analytical data for more complete information.

Appalachian Area. The Appalachian area was the in the U.S. in which petroleum was produced comm

cially and is one of the best known and studied geolo

features of North America. Table 24.3 gives characteristics of some waters produced from

palachian fields. F--~, 24-6

TABLE 24.3-CHARACTERISTICS OF SOME WA

Number of Analyses* System

KentuckyZ3,24

4 Devonian-Silurian

8 Mississippian

5 -

Ohi0 35.36

8 Mississippian

7 Ordovician

8 Mississrppian

Formation

Corniferous

McClosky

Jett

Blue Lick

Sub Trenton

Second Water Big Lime habetically in order of general oil-productive he U.S.. Canada. and Venezuela. rather than by

ler subdivisions of basins. geologic provinces.

nclines. An exception to this is the Illinois PETROLEUM ENGINEERING HANDBOOK

TERS PRODUCED FROM APPALACHIAN FIELDS

Subsurface Depth

(fl)

400 to 1,506

1,390 to 2,618

939 to 1,534

1,843 to 3,263

3,820 to 5,815

2,175 to 3,270

Constituents (mg/L)

Ca Mg Na

1,520 670 9,520 12,160 3,350 44,740 1,700 990 15,700 3,400 2,180 33,600

370 130 1,860 830 320 15,500

1,390 650 10,500 9,230 2,900 33,600

11,000 2,700 39,500 44,000 6,600 58,600 32,300 5,180 36,000

K

120 1,290 ND*

ND ND ND

150 1,510

0 2,890 1,950 Petroleum and associated water are produced from

more than 50 strata in systems from the Cambrian to the

Permian. Most of the productive strata are sandstones,

although some limestones are productive. Many of the

O00000

000

0000000 1,900

- Trace 30 210 114,200 ND 1,230 1.125 167,540

san

the

wid

pala

Ken

con

petr

300

Calduc

Cret

prin

of m

evid

petr

conc

espe

chafield

l

-

s

-

f

f

f

Trace 230 550 193.100 ND 2,100 1.211 324,350 - 0 20 0 52,700 ND 320 1.063 84,260 - 1,800 20 60 93,400 ND 520 1.115 154,820

- -

- -

- - -

30 30 1,100 - - - 560 1,080 83,200 - - -

0 260 30,900 - 0 1,270 75,300 - - - 0 0 490 - - -

40 1.080 97.600

2,790 158,680 41,830

176,590 1,260

157,350

Trace 10 IO 5 70 Trace Trace 1.001 300 830 70 320 121,000 20 1,750 1.149

0 0 0 0 11,330 2 80 1.010 540 70 40 10 81,130 10 700 1.101

IO 5 10 20 5.830 Trace Trace 1.007 1,500 220 1,680 530 89,900 10 500 1.115

10 2::

10 5 2,500 Trace 5 1.004 870 1,330 400 125.000 10 780 1.159 20 Trace Trace 10 44,300 2 40 1.059

760 1.570 270 900 170,000 30 2,500 1.219

475 191,580 18,832

132,110 9,825

148,090 5,810

206,430 51,552

318,630

dstones are nonuniform and discontinuous. although

Big In.jun and Berea sands have been traced across

e areas. The oil-producing states included in the Ap-

chian area from which analyses were available arc

tucky, Ohio. Pennsylvania. and West Virginia. The

centrations ofdissolved salts in waters produced Gth

oleum range from a few hundred to more than

,000 IllgiL.

ifornia. In different fields of California. oil is pro- ed from many reservoirs, ranging in age from

aceous to Pleistocene. Sandstones and sands are the

cipal productive rocks. Many of the formations arc

assive thickness. and much folding and faulting are

ent. In general. mineralized water produced with

oleum from California reservoirs is by no means as

entrated as that from reservoirs in many other areas.

U.S. Gulf Coast. For many years since the Spindletopdome was discovered in 1901, copious quantities of oi

have been produced from Tertiary and Quaternary for

mations on the flanks, in the caprock, and in structure

abovle the capmck of massive salt domes. usually considered intrusive in nature. During recent years. offshore

drilling has focused attention on drilling oft the coasts o

Louisiana and Texas. Some waters produced from gul

coast fields are quite fresh; others have concentrations o

dissolved salts as high as 170.000 nngit, (Table

24.5). 4L44

Illinois Basin. The Illinois basin. divided roughly intohalves by the LaSallc anticline. comprises much of II-

linois and southwestern Indiana. Oil is produced here

from many fields, principally from Pennsylvanian andPROPERTIESOF PRODUCED WATERS

TABLE24.3-CHARACTERISTICSOF SOMEWATERSPR

Ba Sr

Constituents (mg/L)

HCO, SO, Cl

- 0 - 630 - ND - ND

ND ND

628: 10 19,6

690 93,9060 910 31,70

230 3,320 61,00120 50 14,0250 3.200 26.00

Trace 110 30 18,2- 315 380 380 77,6- 0 20 150 113,5- 900 510 490 189,4- 0 60 30 113,0

1,240 140 100 216,3cially the midcontincnt. Table 24.4 gives the

racteristics of some water produced from California s, JO.41 24-7

DUCEDFROMAPPALACHIANFIELDS (continued)

Specific Gravity

I Br 60/600 TDS

O-ML)

Trace 120 10 820 ND ND ND ND ND ND ND ND

1.022 1.120 1.036 1.070 1.020 1.039

31,600 158,330 51,060

103,730 16,530 46,100

0 0 0 1.025 31,030 IO 570 1.089 125,180

0 10 150 1.150 167,030 0 30 600 1.224 304,020 0 ND 580 1.151 189,100 0 ND 1.240 344,110 Mississippian sandstones and. to a smaller extent. from

limestones. TDS in the produced waters range from

about I.000 to more than 160,000 mg/L (Table 24.6).j5

2,900 1,300 15,015 510 1,020 10 3 2,050 0 1,700 80 140 7,090 340 3,900

Tertiary Zone A 18 110 27,100

1,300 9,560

47,995 5,064

21,200 90

l

Montana. New Mexico, Utah, and Wyoming from many 24. I3 present the characteristics of some waters from fields in the Rocky Mt. area. The principal production is

from rocks of the Cretaceous system, although oil and

Canadian fields in Alberta, Manitoba, and Saskatche- wan, hObh5

TABLE 24.5-CHARACTERISTICS OF SOME WATERS PRODUCED FROM GULF COAST FIELDS (TEXAS)

Constituents (mg/L) Subsurface Depth

u9

2,579 to 11 400

40610 1 100

1.305 to 3.296

FormatIon or field Mg

50 Cl

TDS (m9L)

5 700 116900

353 4 500

10,860

54480

10.470

171.300 18.900

109.990

570

Number of

Analyses' System

42 Terilary

5

6 Oligocene

6 Upper Eocene

5 Oligocene

Ca Na

2.240 40.600

60 1.330

3,800

18,200

3.600 61.000

6.700

40.800

340

HCO,

30

990

230

770

70

400

so,

0 3.180 69.100

20 2.130 6.300

33.700

6.100 105000

Fno

Norm Coastal

Goose Creek

Humble

Damon Mound

Barber HIII Dome

1,000

10

30

110

3

160

120

210

Trace 1.750 270

3.010

16

775 to

250to 11 300

63400

110 4 Pliocene-Miocene 70 'Upper ligure in each column IS m~n~murn value and lower figure IS maximum va

Midcontinent Area. The midcontinent oil productive area is the largest geographically of all oil-productive

areas in the U.S. For purposes of this section, it is con-

sidered to include Arkansas, Kansas. northern Loui-

siana, Missouri, Nebraska, Oklahoma. and all of Texas except the gulf coast fields.

Oil and associated brines are produced from many sandstones and limestones, as well as from other types of

formations, in geologic systems ranging from the Cam-

brian through the Upper Crctaceous. Waters produced

with petroleum from midcontinent fields have a wide

range of concentration of dissolved salts, from little

more than 1,000 to more than 350.000 mg/L. Tables

24.7 through 24.9 present the characteristics of some

produced waters from the midcontinent fields of Kansas, Oklahoma, and Texas.36-

Rocky Mt. Area. Petroleum is produced in Colorado, Powell-Mexla 6 ue for number of analyses ndlcated '+I'

associated waters also are produced from Jurassic, Per-

mian, Pennsylvanian, and Mississippian rocks. Pro-

duced waters from Rocky Mt. fields have comparatively

low concentrations of dissolved salts and often are

characterized by comparatively high concentrations of

bicarbonate. Tables 24.10 and 24.11 give the

characteristics of some waters produced from Rocky Mt.

fields of Colorado, Montana, and Wyoming. 55m5y

Canada. The principal oil-productive areas in Canada are the lower Ontario Peninsula, where oil is produced

from rocks ranging from Ordovician to Devonian age,

and the western provinces, principally Alberta, Sas-

katchewan, and the Northwest Territories. Reservoir rocks in western Canada range in age from Devonian to

Cretaceous. Although many of the waters produced with

petroleum have quite low concentrations of dissolved

salts, others are quite concentrated. Tables 24.12 and 24-a PETROLEUM ENGINEERING HANDBOOK

TABLE 24.4-CHARACTERISTICS OF SOME WATERS PRODUCED FROM CALIFORNIA FIELDS

Subsurface Constituents (mg/L)

Depth (fi) Ca Mg Na a

--z- 10 HCO,

1,104 to 1,916 40 50 180 390 340 3,290 480 360

1,495 to 3,250 20 IO 910 0 180 2,890 690 13,250 360 360

2,270 to 3,550 60 20 3,650 0 50 1,280 570 11,650 90 4,270

400 to 3,000 10 10 50 0 20 20 1,550 390 7: - 200 140 4,770 150 0

220 230 7,640 460 0 - 200 10 1,300 0 4

so,

190

TDS Number of Analyses

17

10

System Formation

Tertiary Coalinga

Tertiary Midway

Tertiary Sunset

Tertiary Kern River

Tertiary Lost Hills

Tertiary Maricopa

Cl

90 2,520 1,010

23,550 4,360

21,420 10 60

FwU 580

7.260 14,640 2,140

42,120 8,145

39,320 80

2,130 13,020 21,120

10 1,380

5 40

5

4

2

26

0 20 20

630 2

7,740 11,950 1,170 2,686 1.710 11.490 36400

30

4.460

12.730

230 10

210

610 6.700

21 600

550 30

240

Venezuela. The principal productive formations in oilfield waters are sodium, calcium, and magnesium.

TABLE 24.7-CHARACTERISTICS OF SOME WATERS PRODUCED FROM MID-CONTINENT FIELDS (KANSAS) Subsurface Constituents (nq/L)

Speclflc Number01 Depth ~ Gravely TDS Analyses System Formamn tft) ca blq N.3 Ba HCO, so, Cl I Br (60160~) (mg,L)

-~ 87 Pennsylvanian Kansas C~fy Lansmg 1.228 lo 3.409 2 040 840 16940 4 5 0 34.100 2. 30 1040 53.959 16 DO0 3 950 77.000 70 450 2 160 158.800 15 400 1 159 256.830

8 Ordovlclan WllCOX 3.500 to 3 800 790 5.560 10800 0 20 80 10,870 Trace 80 1015 28.120 14400 68500 142,500 0 530 300 142600 3 x50- 1140 369.180

123 Ordowaan Arbuckle 2.750 lo 3 770 700 240 6 820 0 50 0 12.300 0 Trace ,014 20.180 19 BOO 10.900 34 450 0 640 2 700 79200 Trace 60 1 091 145.060

76 Ordoviaan VIOla 2091 lo 4 14, 620 230 5240 0 IO 20 330 0 5 1012 6,455 11 000 3.110 52000 0 650 1180 112.700 10 90 1116 160.740

27 Pennsylvania Bartlesvllle 625 to 3 200 420 1EO 7550 0 10 1 12.600 2 20 1016 20.782 12 100 3,480 69.800 10 520 750 141 200 10 200 1 141 224.870

20 Mississippian Mississippian 1010 to 4 679 560 220 9 150 0 30 0 14.400 1 2 ,017 24.363 12 900 2.660 59300 20 670 3540 122000 60 3 1140 201.153

8 Basal Pennsylvaman Conglomerate 3320 to 3469 1 000 360 11 600 0 0 0 20.700 0 200 1023 33.850 8 480 2.000 47.000 0 180 700 58,300 Trace 400 1 105 116.660

24 PWlSlWllX Chat 2697f0 3 365 3.120 640 24400 0 30 0 42,700 2 10 1 088 70,902 13480 1.950 66,500 0 130 2.200 137700 3 420 1143 222,383

12 SllUrlan HlO 2 390 to 2 893 230 90 3610 0 70 100 5,300 0 10 1007 9.410 5 220 1.460 36600 3 480 1,230 68.400 2 70 1075 113.460

10 Basal Pennsylvanian Gorham 33ooto 3 854 920 280 6 560 0 160 40 11.300 0 5 1019 19.265 3 960 1.030 17100 10 840 3.010 36,000 0 10 ,045 58,940 Venezuela are Tertiary sandstones and Cretaceous

limestones. In general. the various waters produced with

petroleum have low concentrations of dissolved salts

(Table 24. 14).66m69

Inorganic Constituents

Petroleum companies often analyze oilfield waters to

determine their major dissolved inorganic constituents.

The major constituents usually are sodium, calcium,

magnesium, chloride, bicarbonate, and sulfate. The analytical data are used in studies such as water iden-

tification. log evaluation, water treatment, environmen-

tal impact, geochemical exploration, and recovery of

valuable minerals. 26

Cations

The presence of various cations and anions in oilfield

waters can cause solubility, acidity, and redox (Eh)

potential changes as well as the precipitation and adsotp-

tion of some constituents. The major cations in most 9 Pennsylanlan PrUe 1 032 to 2.400 2.310 11 300

12 Cambraan Reagan 3175f03609 1 390 5 250

Upper fqure I each column IS mlnimum value and lower hgure IS maximum value The concentrations of these ions can range from less than

10.000 mg/L for sodium, and from less than I .OOO mg/L

to more than 30,000 me/L for calcium and/or

magnesium.

Other cations that often are present in oilfield waters in

concentrations greater than 10 mg/L are potassium,

strontium, lithium, and barium. Some oilfield waters

contain concentrations in excess of IO mg/L of

aluminum, ammonium, iron, lead, manganese, silicon, and zinc, 26.70.71

Anions

The major anion in most oilfield waters is chloride. The

chloride concentration can range from less than 10,000

to more than 200,000 mg/L. There are exceptions to

this-e.g., some Venezuelan oilfield waters contain

more bicarbonate than chloride.

Most oilfield waters contain bromide and iodide. The

concentrations of these anions range from less than 50 to

more than 6.000 mg/L for bromide and from less than IO PROPERTIES OF PRODUCED WATERS 24-9

TABLE 24.6-CHARACTERISTICS OF SOME WATERS PRODUCED FROM ILLINOIS FIELDS

Number of Formatton

Subsurface

Depth

Analyses System of field (N

12 Misswloolan Wallersbura 1.994

2 437

18 M~ss~ss~pp~an Tar Springs 1.125

2,596 57 M~ss~ss~pp~an Cypress 1.045

2.960

17 Ordowclan Trenton 672 to 4,000

134 Mwssipplan St Geneweve 1.104 to 3.519

Ca

1.200

2.970 960

6.020 840

6.600

50

7.500

1.900 16.430

Constituents (mg/L)

MC! Na HCO_, so,

640 22.660 30 0 1.020 32.220 390 1 620

IO 240 20 0

1.730 42.810 1.050 980 510 3.970 10 10

1,660 47.900 1.660 3.840 40 340 20 30

1.830 41.830 960 1.350

910 8.740 20 30 3.460 47.660 1.470 2.990

Cl

38 300

56 700 700

76 000

25 800

83 200

200 82 400

14000 95 400

TDS

(mglL)

62.830

93 920 62 930

i 28 590 31 140

143.940

680 135870

25 600

167.940

Upper figure in each column IS minimum value and lower llgure IS ma~~rnum value for number of analyses Indicated 720 14300 0 20 0 28.000 0 0 1033 45.350 2.610 68 700 10 330 50 138.900 0 0 1 139 221.900

310 9 300 0 80 30 14,700 NO ND ,021 26.810 1.370 43000 0 410 2,570 76,900 ND ND 1088 126.930

for number of analyses Ind~caled %+

24-10 PETROLEUM ENGINEERING HANDBOOK

TABLE 24.8-CHARACTERISTICS OF SOME WATERS PRODUCED FROM MID-CONTINENT FIELDS (OKLAHOMA)

Subsurlace Constituents (mg/L)

Speclflc Depth

~--~ _~ Grady TDS

ut1 -~Ca Mg Na Ba HCO, SO, Cl (60/600) (mg/L)

4.489 to 5,524 1.900 910 12,100 0 0 0 24 100 1031

3,436 to 7.233

1,240 10 4.800

542 to 6.094

1.48070 5430

1,800 to 2,490

1,837 lo 4.872

3.927 10 5.977

1.258 to 6.025

1.213 lo 6.495

1,030 to 4.567

1.876 to 2 300

3.197 lo 5,021

2.403 to 4.650

3.458 to 5.004

2.267 to 3.587

982 to 3.163

2 417 to 3,254

790 to 5.000

1.882 to 3.218

2.173 to 7,569

83.800 730 48.300 0 80.230 130 31.300 0 79.000 380 14,000 0 63.800 110 34.600 1 51.500 20 42.500 1 57.700 200 43,600 2 72.000 30

19000 2.740 6.800 1.400 18500 3300 5.300 1,800 18900 4.300 2.200 900 18.800 2,700 4,600 1.400 11.900 4.300 5,900 2.000

13.300 2.600 6400 2000

22,400 2,500 4.600 1.100

18.400 3.200 1 700 600

15.800 3.100 5.600 1.200

17,600 3,000 6.200 1.500 18.700 3.200 6600 1,500 12700 2.500

300 80 28.900 4,300 9.700 1.700 19.600 2.600

200 60 16000 2,400 8.500 1.300 11,700 3.100

740 230 7.300 2,900

14.000 2.200 17.400 3.100 10,900 1,800

300 20

160 10 80 0

850 0

29,500 0 76.000 10 17,600 10 61.300 280

310 15

120 10 80 30

24.400 0 71,900 2 31,700 0

I390 144.000 0 91.300

720 163.000 0 34,900

510 160.000 0 33,000

1.880 127.000 0 65,000

1.130 113.500 0 81.600

200 115.000 24 84.200

430 157.000 60 55,400

1.920 156,000 0 29.800

2,750 121.000 0 50.900

440 140.000 30 64,100

450 139.000 0 90,000

110 20 90

67,400 IO 42,500 0 56,500 240 4.000 0

0 110 IO

130

75.900 170 42,800 5 71.700 220 2900 0

62,000 10 43,400 5

5 140 15

660 3

680 117,000 0 8,200

7.010 142,000 0 101.000

72,900 20 10800 0

20.000 3.500 5.500 900 13.900 2.000

700 400 22.400 3.500

27,900 50 23800 0 76400 5 43200 2 69,000 40 32.000 0 54700 10 11 500 10 80500 450

170 40

940 50

120 20

380 0

50 20 133 50 130

1 175 1 103 1170 1075 1179 1.034 1 147 1073 1 130 1.091 I 129 1095 1 173 1.066 1 173 1.039 1 134 1059 1.159 1075 1157 1.103 1.131 1012 1155 1115 1 164 1005 1137 1 110

1 158 1022 1076 1 160 1 171 1 109 1 163 1073 1 122 1024 1 183

370 149,000 0 4,400

980 122,000 30 86.300

480 142.000 2 18.600

40 63,600 130 132,800 370 156.200 15 99,300

260 149.000 40 45,500

760 108.000 0 19,500

920 167,000

39.010 251 460 147.820 266.010 73.310

263.170 50,100

214.140 105 701 182,660 132,016 189,120 136.212 254440 90,690

250,640 49.730

204.320 82.100

233.042 103,540 228.890 141.050 189.760 11.995

258.948 155.208 243.660

7.600 204.330 139.885 230,320 30.392

102,170 172.930 253,525 155,235 241.930 86.900 179,500 32,110

275,270

Number of Analyses System Formaflon

Bartlesvllle

WllCOX

Layton

Atbuckle

Cromwell

Burgess

Mississippi

Mlsener

Pennsylvanian

Slmpso"

Skinner

Booth

Hunton

Red Fork

VIola

Prue

Healdion

Tonkawa

Burbank

Dutcher

Bromide

75 PennsylvanEln

94 Ordovlclan

25 Pennsyfvanlan

28 Ordovua"

I9 Pennsylvanian

12 Pennsylvanian

22 M~ss~ss~pp~an

18 Mlssisslpplan

I7 Pennsylvaman

10 Ordowan

22 Pennsylvania"

22 Pennsylvama

22 Siluro-Devontan

27 Pennsylvania

12 Ordowclan

20 Pennsyfvan,an

13 Pennsylvanian

15 Pennsylvanian

24 Pennsylvanian

15 Pennsylvanian

14 Ordowuan

TABLE 24.9-CHARACTERISTICS OF SOME WATERS PRODUCED FROM MID-CONTINENT FIELDS (TEXAS)

Number of Analyses System

Subsurface Specific Depth Constituents (mg/L) TDS _ Grawty

Formation (ft) Ca Mg Na so4 HCO, Cl (60~160~) (m9Q

North-Central Texas 50-52

33 Upper Pennsylvanian

El Upper Pennsylvaman

7 Upper Pennsylvanian

13 Upper Cretaceous

20 5 10,700 2.450

1,884 !O 2,081 14,400 2,440

16.700 2.860 2.540 to 2,668 10.200 2,030

13,800 2,440

3.844 to 4.446 3.100 370

7,900 600

530

48.200

58,300

66,800

52,500

61,000 32.100

62,900

61;

1

690

0 300

0 520 0 630

10 740 130 250

410 370

460

97,900

122,200

139,800 106,000

119,000

57.500

112,500

ND

ND

ND

ND ND

ND

ND

ND

1,017

160,550

197,640

226.680 171,360

196,990

93,450

184.680

160 6.030 0 IO 10.000 1.015 16,700 3,000 60,400 180 400 134,000 1.157 221,080 640 15,700 10 40 31,400 1044 50,010

2,300 57,100 650 4,840 109,500 1 145 188,390

350 12,000 4 20 25,300 1.035 39,374

2,850 55.700 1,840 2.140 130,500 1 173 214,330 810 25,500 2 2 82,900 1.105 112,414

3,500 74,300 710 710 161,800 1212 262,320 310 4.400 210 350 19,000 1.033 25,010

7,900 67.000 1.840 4,900 140,500 1 154 241,940

200 210 0 160 890 ND 1,710

Dyson

Landreth

Woodbine

North and West Texas5354

21 Pennsylvanian

35 Pennsylvanian

47 Cambro-Ordovcian

56 Pennsylvanian

50 Permian

42 Permian

Cisco

Canyon

Ellenberger

Straw

San Andres

Big Lime

700 IO 1.950 500

23,100

2.200 IO 7.000 2.200 14.000

3,800 to 8.370 1.700

22.300 1,700 to 6,900 3,200

21.300

740

19.800

- 250 3,700 122,500 0 8,600 212,000 ND 356.600 9.800

PROPERTIES OF PRODUCED WATERS 24-11 TABLE 24.10-CHARACTERISTICS OF SOME WATERS PRODUCED FROM ROCKY MOUNTAIN FIELDS (COLORADO AND MONTANA)

Constrtuents (mg/L)

System

Subsurface

Depth

(ft)

Cretaceous Dakota 2.819 to 5.830

Cretaceous Frontrer 1,230 IO 3.464

Eocene Wasatch 2,230 to 5.283

Jurasw Morrtson 3,020 to 4.395

Jurassrc Sundance 4,564 lo 6,263

Ca Mg

0

NC3 co3 HCO3 so, TDS

Cl ml/L)

310 0 210 40 40 560

13,000 160 3,600 890 22,100 41,220

820 0 340 0 820 1,980

8,200 240 4.900 90 12.800 26.490

1,800 0 120 20 2,000 3.990

10,600 150 2,000 870 18,900 33,830

1,400 0 540 160 260 2.360

3,600 120 3,350 980 5,000 13,160

1,070 0 200 0 260 1,530

5,250 0 3,030 1,040 8,060 17.840

3.900 220

710

6,200

260

4.670

1.110

3,140

30

1,390

20

0 140 0 10 4,050

0 2,000 1,850 5,530 9,770

0 260 0 280 1,250

0 1,400 250 8,800 16,900

0 500 0 10 790

0 4,900 290 6.000 16.010

0 1,670 0 370 3,150

0 4,040 820 2.890 11,060

0 150 1,310 10 1.560

0 400 5.540 440 8,470

0 220 trace 10 250

Number of

Analyses

Colorado5ss6

7

6

6

4

3

Montana5s-s7

Jurassic

Upper Cretaceous

Lower Cretaceous

Upper Jurasw

Pennsylvanian

Upper MIssIssippian

Lower Missrssippian

9

10

11

55

22

25

Montana -

Colorado -

Kootenar -

HIS

Quadrant

Tensleep

Madison

-

0 1,180

0

190

30

900

0

80

0

380

0

70

40

410

0

30

0

80

0

100

0

130

0

90 trace

90

60

680

0

0

70

0

120

0

60

0

80

trace

700

0

500 430 2,330 0 4,830 2,110 2,790 12,990

TABLE 24.11-CHARACTERISTICS OF SOME WATERS PRODUCED FROM ROCKY MT. FIELDS (WYOMING)

Constttuents (mg/L) -

CO, HCO, Na

410 trace 280

5,560 230 1,900

550 trace 1,270

20,000 1,050 7,800

200 trace 1,000

5,320 320 5.460

1,740 trace 890 7,000 590 6.950

1,040 trace 110

6,210 300 2,290

180 trace 230

13,000 280 6,900

630 trace 1.000 5.560 380 3.680

180 0 480

430 60 980

520 0 410

6,800 330 6.850

140 0 210

5,170 0 1.690

5 0 30 790 10 1,000

20 trace 20

580 20 1,080

630 0 190

1,670 0 550

Subsurface

Depth

(4

900 to 1,300

1,000 to 3.080

TDS Number of

Analvses System Ca Mg 10

330

so, 0

3,710

trace 240

trace

60

trace

880

0

110

20 980

trace 60

60

820

40

5,880 190

5,790

10

2,500 50

1,940 1,930

3,870

Cl @WLl

20 ~ 730

Formatron

Shannon

Frontier

First Wall Creek

Second Wall Creek

Cleverly

Dakota

Dakota

Greybull

Sundance

Embar

Tensleep

Madtson

Mmnelusa

10

250

24 Cretaceous

7,670 19.650

70 1,890 27,900 57.340

220 1,420 5,940 17.230

1,170 3,800 6,600 22.070

150 1,300

7,590 16,630

20 450

19,200 40,750

110 1,740 1,930 11.730

40 760

90 2.420

140 1.110

35 Cretaceous

45 Cretaceous

50 Cretaceous

14 Jurassrc

22 Jurasstc

24 Jurasstc

5 Jurassrc

60 Jurassic

20 Permian

50 Pennsylvaman

19 Mississippian

20 Triassic

trace trace

220 130

trace trace

30 100

trace trace 40 10

trace trace

110 20

trace trace 230 160

trace trace 60 60

irace trace

40 trace

0 0

400 60

140 30 630 220

40 10

720 250

20 trace

870 180 250 50

450 60

-

1,400 to 1.500

4,050 to 4.505

4,353 to 8.500

-

- 7,700 28,020

10 620

3,930 17,430

3 98

1,080 6,350 4 114

1,070 5.740

250 3,300

610 7,210

-

-

-

31 200 - 1 033 25 680

many oilfield waters. Their concentrations can range volume per unit water volume per psi change in pressure. from none to several thousand milligrams per liter.

Other anions found in oilfield waters include arsenate, This is expressed mathematically as

borate, carbonate, fluoride, hydroxide, organic acid I av (',,. = -- ( >

-

salts, and phosphates. Boron concentrations in excess of T, _. _. (la)

100 mg/L can affect electric log deflections. 26 v ap

This sechon. except for the pH and Eh, was writlen by Howard B Bradley

TABLE 24.13-CHARACTERISTICS OF SOME WATERS PRODUCED FROM CANADIAN FIELDS, PROVINCE OF SASKATCHEWAN

Subsurface Number of Depth Constituents (mg/L)

Spectffc

Analyses System Formatron (W Ca Mg Na Gravrty TDS

CO, HCO, SO, Cl (60/600) (ma/L) 27 Cretaceous Blafrmore 998 to 3,713 ~ ~ trace trace 2,200x---- 190 - 2.800

5

5

25

12

9

11

4

11

Shaunavon 3,205 to 3.413

Gravelbourg 3.290 to 4.175

Mfssron Canyon 3,700 to 5,785

Ntsku 4,682 to 6,927

Duperow 2,253 to 4,024

Mississippian 4,487 to 5,665

Lodgepole 2.305 to 4,470

80 1,300 - 190

- 300

- 140

- 350

- 60

- 440

- 200

- 2,350

- 100

- 860 - 120

110 850

- 480

- 600

- 70 - 2,600

- 40

- 1,580

1 000 6,190

8

Devonian

Devonian

MissIssippIan

Mississippian

Lower

Cretaceous

Devonian

Viking 2,395 to 3,026

Devonian 3,356 to 6,605

2,300 870 20,300 170 100 8,800

1,850 230 t 2,400 470 220 11,700 620 370 t 2.900 100 130 760

7.100 3,100 73.700 740 190 1,000

14,100 7.150 73,000 680 170 940

9,000 900 17.700 trace trace 4,300 5,600 1,600 71,000 730 90 1,400

2.800 610 27,000

trace trace 1,100 190 100 9,300

0 0 0

1,100 1,200 69,100

3,500 2,100

3,100

270

2,100

3,200 Trace

2,500

2,200

5,000 340

3,900

3,400

3,900

38,900 1.048 67,250 890 1.007 12.250

t 3,800 1.014 31.580 14,500 1 022 27.300 20,100 1.026 36.440

280 1.001 1.330 155,000 1 093 242.540

640 1 002 2.770

142,800 1 186 242.600 700 t ,002 4,790

31,100 1.040 64,560 5,700 1.004 10.460

123,800 1 150 206,860

580 1.004 6,680 45,700 1 061 80,610

0 2,100 1.002 3,270 790 12,700 1.014 25,680 190 4,800 1.012 5,030

2,400 111.000 1.160 185,380 1,322 lo 2 553

2516fO4604

1.698 to 3 717

to more than 1,400 mg/L for iodide. 26 Bromide concen-

tration is important in determining the origin of an

oilfield brine and is an important geochemical marker

constituent. Bicarbonate and sulfate are present in a Jurassic Jurassfc shale 3,105 to 4,325 trac8,10

Upper ftgure tn each column IS mmmum value and lower figure is maxmum value 530 8.800 7.900

173.500 14.300

154 900

- 1 002 1 840 - 1 025 25 780 - 1 025 16.120 - 1180 290.070 ~ 1 026 26 760 - 1176 264,300

Physical Properties of Oilfield Waters* Compressibility

The compressibility of formation water at pressures

above the bubblepoint is defined as the change in water 24-12 PETROLEUM ENGINEERING HANDBOOK

TABLE 24.12-CHARACTERISTICS OF SOME WATERS PRODUCED FROM CANADIAN FIELDS

Number of AllalySeS System Formalton

Subsurface Depth

ml

Specllic Constltenls (mJ/L, GLWy TDS

Ca Mg Na CO, HCO, SO, Cl I Br ~60/60l (mg/L)

215 10 1,890

1.670 10 2 072

2 706 10 2,744

10 10 660 0 320 5 50 10 3.000 80 790 600 70 20 6400 0 580 20

620 230 19.000 60 640 40 29.200 5 60 1 030 0 180 0 670

1.250 190 9.100 410 1250 2500 - -

1.570 to 3 323

2.200 to 2 942

3.000 lo 3 422

870 to 2 060

980 850 0 100 1 000 67 340 44.900 40 2.140 4,600

240 4.900 0 110 900 2.000 81.400 30 360 4.900

550 21.300 0 80 3900 1 400 72.800 80 780 4.300

200 4.500 6.400

11.000

- -

-

850 94,900

7.000 149.600

34 900 120 700

740

ND ND ND 1 205 NO ND ND 9,030

10 10 1010 13.510 40 620 1 060 64.160

ND ND 1 006 2.145 ND ND 1 032 25.700

0 10 - - 20 460 - -

2 20 - - 20 220 - -

3 90 ~ - 10 110 - -

2 200 - - 20 1.500 - -

- 1010 3.940 - ,089 150 380 - 1016 14.150 - 1157 248.990 ~ 1031 62 930 - 1136 203 880 - 1 004 3 150 - 290

- 1,320

e trace 4,300 0 160 10,900

0 2,800 1.002 7,390 3,600 15,400 1.029 39,480

far number of analyses mdlcafed 65

or

1 v*--v, T,=-

( > v PI--P2 , . . . . . . . . . . . . . . . . . . . . .

01

Bw2 -B,I c,.= - B,.(p, -p2), . . . . . . . . . . . . . .

(lb)

where

CkV = water compressibility at the given pressure

and temperature, bbl/bbl-psi,

-cw = average water compressibility within the

given pressure and temperature interval,

bbl/bbl-psi,

V = water volume at the given pressure and

temperature, bbl,

V = average water volume within p and T inter-

vals, bbl,

PI and p2 = pressure at conditions 1 and 2 with p r >pz,

psi, B,,, and B 4 = water FVF p I and ~2, bbl/bbl, and B,. = average water FVF corresponding to V,

bbhbbl.

Eq. 2 was fit for pressures between 1,000 and 20,000

psi, salinities of 0 to 200 g NaClIL, and temperatures

from 200 to 270F. Compressibilities were independent

of dissolved gas.

solution on compressibility of water with NaCl concen-

trations up to 200 g/cm3 is essentially negligible. Osifs

results show no effect at gas/water ratios (GWRs) of 13

scf/bbl, at GWRs of 35 scf/bbl probably no effect, but

certainly no more than a 5% increase in the com-

pressibility of brine. Laboratory measurements 74 of water compressibility

resulted in linear plots of the reciprocal of compressibili-

ty vs. pressure. The plots of l/c, vs. p have a slope of

m r , and intercepts linear in salinity and temperature. Data points for the systems tested containing no gas in

solution resulted in Eq. 2.

l/c~,=m~p+m~C+m~T+m4, (2)

where

cw = water compressibility, psi - ,

p = pressure, psi,

C = salinity, g/L of solution,

T = temperature, F,

ml = 7.033,

m2 = 541.5,

lfl3 = -531, and

m4 = 403.3 X 103. PROPERTIES OF PRODUCED WATERS

TABLE 24.14-CHARACTERISTICS OF SOME WAT

Number of

Analyses

5

7

6

7

a

8

7

8

10

11

System Formation or Fteld

Tertiary Zeta (Quiriquire)

Tertiary

Tertiary

Cretaceous

Tertiary

Tertiary

Tertiary

Cretaceous

Eta (Quiriquire)

Cabtmas field, La Rosa formation

Lagunillas field,

lceota formatlon

Bachaquero field,

Pueblo Viejo main sandstone

Mene Grande field,

Pauji and Mason-Trujillo range

La Conception field. Punta Gorda sands and deeper sands

La Paz field,

Guasare formation

Cretaceous

Tertiary

S. El Mene field,

El Salto formation

Oficma and W. Guard ftelds

OF, sand

AB, sand

D, sand Du and Eu sands

F, sand

H sand

L, sand M sand

P sand

S sand

U sand

Upper tlgure I each column 1s minimum value and lower figure IS maximum valueIn an oil reservoir, water compressibility also depends

on the salinity. In contrast to the literature, laboratory

measurements by Osif 74 show that the effect of gas in 24-l 3

ERS PRODUCED FROM VENEZUELAN FIELDS

Constituents (mg/L) TDS

Ca Mg Na CO, HCO, SO, Cl -- ~

(mglL)

170 100 1,750 0 3,050

330 270 5.150 0 5.400

70 50 400 300

60 60

10 60

40 60

2:040 0 12,360 0

1,740 0

2,000 120

4,610 0

1,800 100

4,700 1,900

3;050 7.410

2,010

5,260

6,250

30 20 3,570

50 20 30

30 20 6,000 80 1,230

30 50 2,660 0 1,130

30 40 3,000 0 1,130

150 50 9,000 0 2,440

50 20 1,260 0 2,330

40 30 1,360 0 2,780

40 30 3,080 0 1,100

40 60 4,000 0 1,430

140 70 7,900 0 3,500

70 70 8,400 0 2,050

160 100 7,300 0 4,420

110 30 7,700 0 2,100

140 80 7,800 0 970

330 80 8,600 0 1,700

940 180 11,800 0 1,100

4 1,910 7,190

10 5,420 16,260

5 710 6,900 30 11 ,170 36,500

0 1,780 5,643

0 90 5,260

5 3,700 14,657

0 690 6.210

0 6,250 12,955

0 8,550 15.911

0 3,450 7,320

0 1,260 5,460

0 9,000 20,640

140 640 4,424

60 560 4,830

130 4,230 8,520 0 5,500 11,030

150 10,500 22,260

10 12,090 22,690

trace 9,260 21,240

20 10,900 20,860

0 11,600 20,590 100 13,050 23,860

0 19,800 33,820

for number ot analyses mdlcated - Where conditions overlap, the agreement with the

results reported by both Dorsey 75 and Dotson and Stand-

ing 76 is very good. Results from the Rowe and Chou

voir pressure. Note that for oil reservoirs below the bub-

blepoint, the saturated-with-gas curves should be

used; for water considered to have no solution gas, the no-gas-in-solution curves should be used. These

curves were computed from data given by Ashby and

Hawkins. 24-14

Fig. 24.4-Specific gravity of salt solutrons at 60F and 14.7 psia.

equation agree well up to 5.000 psi (their upper pressure

limit) but result in larger deviations with increasing

pressure. In almost all cases, the Rowe and Chou com-

pressibilities are less than that of Eq. 2.

Density

The density of formation water is a function of pressure,

temperature. and dissolved constituents. It is determined

most accurately in the laboratory on a representative

sample of formation water. I7 The formation water den-

sity is defined as the mass of the formation water per unit

volume of the formation water. For engineering pur-

posts, density in metric units (g/cm) is considered

equal to specific gravity. Therefore, for most engineer-

ing calculations density and specific gravity are

interchangeable. e

When laboratory data are not available, the density of

fomration water at reservoir conditions can be estimated

(usually to within & 10%) from correlations (Figs. 24.4 through 24.6). The only field data necessary are the den-

sity at standard conditions, which can be obtained from

the salt content by use of Fig. 24.4. The salt content can PETROLEUM ENGINEERING HANDBOOK

Fig. 24.5-Density of NaCl solutions at 14.7 psia vs. temperature.

be estimated from the formation resistivity (obtained

from electric log measurements) by use of Fig. 49.3 (see

Chap. 49). The density of formation water at reservoir

conditions can be calculated in four steps.

I. Using the temperature and density at atmospheric

pressure, obtain the equivalent weight percent NaCl

from Fig. 24.5.

2. Assuming the equivalent weight percent NaCl re-

mains constant. extrapolate the weight percent to reser-

voir temperature and read the new density.

3. Knowing the density at atmospheric pressure and

reservoir temperature, use Fig. 24.6 to find the increase in specific gravity (density) when compressed to reser- 4. The density of formation water (g/cm) at reservoir

conditions is the sum of the values read frotn Figs. 24.5

and 24.6. They can be added directly since the metric

24-15 PROPERTIES OF PRODUCED WATERS

units are referred to the common density base of water (1

g/cm3). The metric units can be changed to customary

units (1 bmicu ft) by multiplying by 62.37.

Also the specific gravity of formation water can be estimated if the dissolved solids are known. The equa-

tion is

y,*>=1+c,~xo.695x10-6, . . . . . I.. . .(3)

where Csd is the concentration of dissolved solids

(mgfL). For precise but very detailed calculations, the reader is

referred to a recent paper by Rogers and Pitzer. 79 They

tabulated a large number of values of compressibility, expansivity and specific volume vs. molality ,

temperature, and pressure. A semiempirical equation of

the same type found to be effective in describing thermal

properties of NaCl (0.1 to 5 molality) was used to

reproduce the volumetric data from 0 to 300C and I to

1,000 bars.

Formation Volume Factor (FVF)

The water FVF, II,., is defined as the volume at reser-

voir conditions occupied by 1 STB of formation water

plus its dissolved gas. It represents the change in volume

of the formation water as it moves from reservoir condi-

tions to surface conditions. Three effects are involved:

the liberation of gas from water as pressure is reduced,

the expansion of water as pressure is reduced. and the

shrinkage of water as temperature is reduced. The water FVF also depends on pressure. Fig. 24.7 is

a typical plot of water FVF as a function of pressure. As the pressure is decreased to the bubblepoint, ph. the FVF

increases as the liquid expands. At pressures below the

bubblepoint. gas is liberated, but in most cases the FVF still will increase because the shrinkage of the water

resulting from gas liberation is insufficient to counter-

balance the expansion of the liquid. This is the effect of the small solubility of natural gas in water.

The most accurate method of obtaining the FVF is from laboratory data. It also can be calculated from den-

sity correlations if the effects of solution gas have been

accounted for properly. The following equation is used

to estimate B,,. if solution gas is included in the laboratory measurement or correlation of P,.~:

H,,=L,.. VW P r

. . (4)

where

V,. = volume occupied by a unit mass of water at reservoir conditions (weight of gas

dissolved in water at reservoir or standard

conditions is negligible), cu ft,

V,,. = volume occupied by a unit mass of water at standard conditions, cu ft,

p,(. = density of water at standard conditions,

lbmicu ft, and

prc. = density of water at reservoir conditions,

lbmicu ft. The density correlations and the methods of estimating

P,,~ and prc. were described previously. Fig. 24.6--Specific gravity increase with pressure--salt water

pb PRESSURE, PSI A

Fig. 24.7-Typical plot of water FVF vs. pressure

the Eh. In buried scdimcnts, it is the aerobic bacteria that 24-16

The FVF of water can be less than one if the increase

in volume resulting from dissolved gas is not great

enough to overcome the decrease in volume caused by increased pressure. The value of FVF is seldom higher

than I .06.

Resistivity

The resistivity of formation water is a measure of the

resistance offered by the water to an electrical current. It

can be measured directly or calculated. The direct-

measurement method is essentially the electrical

resistance through a 1 -m cross-sectional area of I m7

of formation water, The fomlation water resistivity,

R ,, $, is expressed in units of Q-m. The resistivity of for- mation water is used in electric log interpretation and for

such use the value is adjusted to formation

temperature. i (See Chap. 49 for more information).

Surface (Interfacial) Tension (IFT)

Surface tension is a measure of the attractive force acting

at a boundary between two phases. If the phase boundary

separates a liquid and a gas or a liquid and a solid, the at- tractive force at the boundary usually is called surface

tension; however. the attractive force at the interface

between two liquids is called IFT. IFT is an impor-

tant factor in enhanced recovery processes (see Chap.

47. Chemical Flooding, describing Low-1FT Proc-

CSSCS and Phase Behavior and IFT in the

Miccllar/Polymer Flooding section).

Surface tension is measured in the laboratory by a ten-

siometer. by the drop method, or by other methods. Descriptions of these methods arc found in most physical

chemistry texts.

Viscosity

The viscosity of formation water, p,, , is a function of

pressure. temperature. and dissolved solids. In gcncral,

brine viscosity increases with increasing prcsaure, in-

creasing salinity. and decreasing tempcraturc.

Dissolved gas in the fomlation water at reservoir condi-

tions generally results in a negligible effect on hater

viscosity. There is little information on the actual

numerical cffcct of dissolved gas on water viscosity.

Gas in solution behaves entirely differently from gas in

hydrocarbons. * In water the presence of the gas actually

causes the water molecules to interact with each other

more strongly, thus increasing the rigidity and viscosity of the water. However. this effect is very small and has

not been measured to date. In the physical chemistry

literature there is an enormous amount of indirect

evidence to support this concept. For the best estimation of the viscosity of water. the

reader is referred to a paper by Kestin (11 (11. Their cor-

relating equations involve 32 parameters for calculating

the numerical effect of pressure, temperature. and con- ccntration of aqueous NaCl solutions on the dynamic and

kinematic viscosity of water. Twenty-eight tables

gcncratcd from the correlating equations cover a

temperature range from 20 to 150C. a pressure range from 0. I to 35 mPa. and a concentration range from 0 to

6 molal. PETROLEUM ENGINEERING HANDBOOK

Figs. 24.X through 24. IO may be used to approximate water viscosity for engineering purposes. These figures

show the effects of pressure, temperature, and NaCl con-

tent on the viscosity of water. They may be used when

the primary contaminant is sodium chloride.

Some engineers assume that reservoir brine viscosity

is equal to that of distilled water at atmospheric pressure

and reservoir temperature. In this case it is assumed that

the viscosity of brine is essentially independent of

pressure (a valid premise for the pressure ranges usually

encountered).

The pH

The pH of oilfield waters usually is controlled by the COfibicarbonate system. Because the solubility of CO?

is directly proportional to temperature and prcssurc, the

pH measurement should be made in the field if a close- to-natural-conditions value is desired. The pH of the

water is not used for water identification or correlation

purposes. but it does indicate possible scale-forming or

corrosion tendencies of a water. The pH also may in- dicate the presence of drilling-mud filtrate or well-

trcatmcnt chemicals.

The pH of concentrated brines usually is less than 7.0.

and the pH will rise during laboratory storage. indicating

that the pH of the water in the reservoir probably is ap-

preciably lower than many published values. Addition of

the carbonate ion to sodium chloride solutions will raise

the pH. If calcium is present, calcium carbonate precipitates. The reason the pH of most oilficld waters

rises during storage in the laboratory is because of the

fomlation of carbonate ions as a result of bicarbonate

decomposition.

The Redox Potential (Eh)

The redox potential often is abbreviated Eh, and also

may be referred to as oxidation potential. oxidation-

reduction potential, or pE. It is expressed in volts. and at

equilibrium it is related to the proportions of oxidized

and reduced species present. Standard equations of

chemical thermodynamics express the relationships.

Knowledge of the redox potential is useful in studies

of how compounds such as uranium. iron. sulfur. and

other minerals are transported in aqueous systems. The

solubility of some elements and compounds depends on

the redox potential and the pH of their environment. Some water associated with petroleum is interstitial

(connate) water, and has a negative Eh: this has been

proved in various field studies. Knowledge of the Eh is

useful in determining how to treat a water before it is

rein.jected into a subsurface formation. For example. the

Eh of the water will be oxidizing if the water is open to

the atmosphere, but if it is kept in a closed system in an

oil-production operation the Eh should not change ap-

preciably as it is brought to the surface and then rein-

jetted. In such a situation. the Eh value is useful in deter-

mining how much iron will stay in solution and not

deposit in the wellbore.

Organisms that consume oxygen cause a lowering of attract organic constituents, which remove the free oxy-

gen from the interstitial water. Sediments laid down in a shoreline environment will differ in degree of oxidation

PROPERTIES OF PRODUCED WATERS

I I191111 I I

1000 10,000

PRESSURE, PSILI

Fig. 24.8-Effect of pressure on the viscosity of water

compared with those laid down in a deepwater environ-

ment. For example, the Eh of the shoreline sediments

may range from -50 to 0 mV, but the Eh of deepwater sediments may range from - 150 to - 100 mV.

The aerobic bacteria die when the free oxygen is total-

ly consumed; the anaerobic bacteria attack the sulfate

ion, which is the second most important anion in the

seawater. During this attack. the sulfate reduces to

sulfite and then to sulfide; the Eh drops to -600 mV,

H 2 S is liberated, and CaCO 3 precipitates as the pH rises

above 8.5.

Dissolved Gases

Large quantities of dissolved gases are contained in

oilfield brines. Most of these gases are hydrocarbons;

however, other gases such as CO2 , N?. and HzS often

are present. The solubility of the gases generally

decreases with increased water salinity, and increases

with pressure.

Hundreds of drillstem samples of brine from water- bearing subsurface formations in the U.S. gulf coast area

were analyzed to determine their amounts and kinds of

hydrocarbons. 2o The chief constituent of the dissolved

gases usually was methane, with measurable amounts of ethane, propane, and butane. The concentration of the

dissolved hydrocarbons generally increased with depth

in a given formation and also increased basinward with

regional and local variations. In close proximity to some

oiltields, the waters were enriched in dissolved

hydrocarbons, and up to I4 scf dissolved gasibbl water

was observed in some locations. A more detailed discus-

sion of this topic is given in Chap. 22.

Organic Constituents

In addition to the simple hydrocarbons, a large number

of organic constituents in colloidal, ionic, and molecular

form occur in oilfield brines. In recent years, some of these organic constituents have been measured quan-

titatively. However, many organic constituents are pre-

sent that have not been determined in some oilfield 24-17

TEMPERATURE , .F

Fig. 24.9-Viscosity of sodium chloride solutions as a function of temperature and concentration at 14.7 psia.

brines primarily because the analytical problems are dif-

ficult and very time-consuming.

Knowledge of the dissolved organic constituents is im-

portant because these constituents are related to the

origin and/or migration of an oil accumulation, as well

as to the disintegration or degradation of an accumula-

tion. The concentrations of organic constituents in

oilfield brines vary widely. In general, the more alkaline

the water, the more likely that it will contain higher con-

centrations of organic constituents. The bulk of the

organic matter consists of anions and salts of organic

acids: however, other compounds also are present.

; 0.611 I I / I 1 i- m 0 0.5. ,o

\ TEMPERATURE, F

Fig. 24.10-Effect of temperature on viscosity of water.

lustrate the relative amount of each radical present. The 24-18

Knowledge of the concentrations of benzcnc. toluene,

and other components in oilfield brines is used in ex-

ploration. The solubilities of some of these compounds

in water at ambient conditions and in saline waters at elevated tern eraturex

determined. x3. f:

and pressures have been

However. the actual concentrations of these and other organic constituents in subsurface oilfield brines is

another matter. It has been shown experimentally that

the solubilities of some organic compounds found in

crude oil increase with temperature and pressure if

pressure is maintained on the system. The increased

solubilitiea become significant above 150C. The

solubilities decrease with increasing water salinity.

Waters associated with paraffinic oils are likely to con-

tain fatty acids. while those associated with asphaltic oils

more likely contain naphthenic acids.

Quantitative recovery of organic constituents from

oilfield brines is difficult. Temperature and pressure

changes. bacterial actions. adsorption. and the high

inorganic/organic-constituents ratio in most oilfield

brines are some reasons why quantitative recovery is

difficult.

Interpretation of Chemical Analyses Oilfield waters include all waters or brines found in

oilfields. Such waters have certain distinct chemical

characteristics.

About 70% of the world petroleum reserves are

associated with waters containing more than 100 g/L

dissolved solids. A water containing dissolved solids in

excess of 100 g/L can be classified as a brine. Waters

associated with the other 30% of petroleum reserves con-

tain less than 100 g/L dissolved solids. Some of these

waters are almost fresh. However, the presence of

fresher waters usually is attributed to invasion after the

petroleum accumulated in the reservoir trap. Examples of some of the low-salinity waters can be

found in the Rocky Mt. areas in Wyoming fields such as

Enos Creek, South Sunshine. and Cottonwood Creek.

The Douleb oil field in Tunisia is another example.

The composition of dissolved solids found in oilfield

waters depends on several factors. Some of these factors

are the composition of the water in the depositional en-

vironment of the sedimentary rock, subsequent changes by rock/water interaction during sediment compaction.

changes by rock/water interaction during water migra-

tion (if migration occurs), and changes by mixing with

other waters, including infiltrating younger waters such as meteoric waters. The following are definitions of

some types of water.

Types of Water

Meteoric Water. This is water that recently was in- volved in atmospheric circulation: furthermore, the age

of meteoric groundwater is slight when compared with

the age of the enclosing rocks and is not more than a

small part of a geologic period. I

Seawater. The composition of seawater varies somewhat, but in general will have a composition

relative to the following (in mg/L): chloride--19.375, bromide-67, sulfate-2,712. potassium-387. sodium

- 10,760, magnesium- 1,294, calcium-4 13, and stron-

tium-8. PETROLEUM ENGINEERING HANDBOOK

Interstitial Water. Interstitial water is the water con mined in the small pores or spaces between the minute

grains or units of rock. Interstitial waters are .snl,yc,,trric'

(formed at the same time as the enclosing rocks) or cyigcrwric (originated by subsequent infiltration into

rocks).

Connate Water. The term connate implies born. produced. or originated together-connascent. There-

fore. connate water probably should bc considered an in-

terstitial water of syngenetic origin. Connate water of

this definition is fossil water that has been out of contact with the atmosphere for at least a large part of a geologic

period. The implication that connate waters are only

those born with the enclosing rocks is an undesirable

restriction.

Diagenetic Water. Diagenetic waters are those that have changed chemically and physically, before. during, and

after sediment consolidation. Some of the reactions that

occur in or to diagenetic waters include bacterial. ion ex- change, replacement (dolomitization). infiltration by

permeation, and membrane filtration.

Formation Water. Formation water. as defined here, is water that occurs naturally in the rocks and is present in

them immediately before drilling.

Juvenile Water. Water that is in primary magma or derived from primary magma is juvenile water.

Condensate Water. Water associated with gas sometimes is carried as vapor to the surface of the well

where it condenses and precipitates because of

temperature and pressure changes. More of this water

occurs in the winter and in colder climates and only in

gas-producing wells. This water is easy to recognize because it contains a relatively small amount of dis-

solved solids, mostly derived from reactions with

chemicals in or on the well casing or tubing.

Water analyses may be used to identify the water

source. In the oil field one of the prime uses of these

analyses is to determine the source of extraneous water

in an oil well so that casing can be set and cemented to

prevent such water from flooding the oil or gas horizons.

In some wells a leak may develop in the casing or ce-

ment, and water analyses are used to identify the water-

bearing horizon so that the leaking area can be repaired.

With the current emphasis on water pollution prevention.

it is very important to locate the source of a polluting

brine so that remedial action can be taken.

Comparisons of water-analysis data are tedious and time-consuming; therefore. graphical methods are com-

monly used for positive, rapid identification. A number

of systems have been developed. all of which have some

merit.

Graphic Plots

Graphic plots of the reacting values can be made to il- graphical presentation is an aid to rapid identification of

a water and classification as to its type. Several methods

have been developed.

deposited under marine conditions, while 15% were PROPERTIES OF PRODUCED WATERS

Tickell Diagram. The Tickell diagram was developed using a six-axis system or star diagram. X5 Percentage

reaction values of the ions are plotted on the axes. The

percentage values are calculated by summing the equivalent proton masses (EPMs) of all the ions.

dividing the EPM of a given ion by the sum of the total

EPMs, and multiplying by 100.

The plots of total reaction values, rather than of

percentage reaction values, are often more useful in

water identification because the percentage values do not

take into account the actual ion concentrations. Water

differing only in concentrations of dissolved constituents cannot be distinguished.

Stiff Diagram. Stiff plotted the reaction values of the

Reistle Diagram. Reistle devised a method of plotting

ions on a system of rectangular coordinates. 87 The cat-

water analyses by using the ion concentrations. * The

ions are plotted to the left and the anions to the right of a

vertical zero line. The endpoints then are connected by

data are plotted on a vertical diagram. with the cations

straight lines to form a closed diagram, sometimes called a butterfly diagram. To emphasize a constituent that

plotted above the central zero line and the anions below.

may be a key to interpretation, the scales may be varied

by changing the denominator of the ion fraction. usually

This type of diagram often is useful in making regional

in multiples of 10. However, when a group of waters is being considered, all must be plotted on the same scale.

correlations or studying lateral variations in the water of

a single formation because several analyses can be plot-

ted on a large sheet of paper.

Many investigators believe that this is the best method of comparing oilfield water analyses. The method is sim-

ple. and nontechnical personnel can be easily trained to

construct the diagrams.

Other Methods. Several other water identification diagrams have been developed, primarily for use with

fresh waters, and they are not discussed here. The Stiff

and Piper diagrams, 87