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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