Calcium Carbonate Deposition in Geothermal - Stanford University

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Calcium Carbonate Deposition in Geothermal - Stanford University

CALCIUM CARBONATE DEPOSITION IN

GEOTHERMAL WELLBORES

MIRAVALLES GEOTHERMAL FIELD

COSTA RICA

A Report

Submitted to the Deparment of Petroleum Engineering

of Stanford University

in partial fulfillment of the requirements

for the degree of

MASTER OF SClENCE

by

Eduardo Granados

June 1983


Stanford Geothermal Program

Interdisciplinary Research in

Engineering and Earth Sciences

STANFORD UNIVERSITY

Stanford, California

SGP-TR-67

CALCIUM CARBONATE DEPOSITION IN

GEOTHERMAL WELLBORES

MIRAVALLES GEOTHERMAL FIELD

COSTA RICA

BY

Eduardo Granados

June 1983

Financial support was provided through the Stanford

Geothermal Program under Department of Energy Contract

No. DE-AT-03-80SF11459 and by the Department of Petroleum

Engineering, Stanford University.


ABSTRACT

Calcium carbonate deposition takes place in the wells of

the Miravalles geothermal field in Costa Rica. Data from

three long term flow test periods performed in well PGM-1

are analyzed through different methods, especially for the

third and longest period which took place after mechanical

scale removal had been performed. For this test a

collection of chemical and thermodynamic data is used to

investigate the evolution of the well production with time.

Hotter fluids are suspected to enter the well at the end of

the test, counting for higher enthalpy values and decrease

in scale deposition rate. Remedial actions are suggested to

reduce the scale deposition rate, or to remove the deposits

formed, taken from the experience gained in different

geothermal fields in the world, dealing with the same

problem.


AKNOWLEDGEMENT

The author wishes to thank all the persons and

institutions that in some form made possible

to complete this work. Appreciation is specially

expressed to Dr. Jon S. Gudmundsson and Dr. Roland

N. Horne for their guidance and support in prepa-

ring this report.


ABSTRACT

TABLE OF CONTENTS

1 . INTRODUCTION ............................................ 1

2 . THE MIRAVALLES GEOTHERMAL FIELD ......................... 3

3 . DRILLING AND COMPLETION ................................. 6

4 . PRODUCTION HISTORY ...................................... 8

4.1 Flow Test Period 1 .................................. 9

4.2 Flow Test Period 2 .................................. 10

4.3 Cleaning Operations ................................. 10

4.4 Flow Test Period 3 .................................. 11

5 . ANALYSIS OF PRODUCTION MEASUREMENTS ..................... 13

6 . WORLD EXPERIENCE OF CALCIUM CARBONATE ................... 17

7 . CALCIUM CARBONATE CHEMISTRY ............................. 21

8 . CHEMICAL SAMPLING AND ANALYSIS .......................... 25

8.1 Sampling and Analysis Methods ....................... 25

8.2 Chemical Analysis ................................... 26

9 . DEPOSITION ANALYSIS ..................................... 28

9.1 Electric Power Research Institute Program ........... 28

9.2 National Energy Authority (Iceland) Program ......... 30

9.3 Rice University Method .............................. 32

10 . FLASHING POINT .......................................... 34

11 . REMEDIAL ACTIONS ........................................ 33

11.1 Mechanical Removal ................................. 39

11.2 Running Liner to Wellhead .......................... 40

11.3 Well Location and/or Deepening ..................... 41

12 . CONCLUSIONS ...................................................... 43

REFERENCES .............................................. 45

APPEND1 X

~ ~~


1. INTRODUCTION

In countries like Costa Rica that have no fossil fuel

resources geothermal energy exploration and development are

most important. Geothermal resources in Costa Rica have

been under exploration since 1963. Extensive studies carried

out in the Guanacaste province have resulted in the

discovery of a geothermal field in the slopes of the

Miravalles volcano. In 1979, the first geothermal well

drilled in Miravalles was put on discharge, setting an

important mark in the history of energy development in Costa

Rica. The Miravalles geothermal field is being explored and

developed by the Instituto Costarricense de Electricidad

(ICE), the national utility for electric power generation.

Two more wells were drilled in the Miravalles area for

exploratory purposesqwith the same success of the first one,

and the plans were laid for the continuation of the

explotation of the field.

While testing the existing wells, a very important

problem started to develop: calcium carbonate deposits would

form at the level of the flashing point in the two most

promising wells, thus decreasing their production and

jeopardizing the future of the project itself.

scaling of calcium carbonate is a widely known problem in


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hot water reservoirs, specially those with temperatures in

the range of 200 to 240 'C.

In many instances, a water geothermal reservoir will

change and evolve with time under continuous production

conditions, and sometimes these changes can be significant

in amount and importance and may be detected at the surface.

The changes that occur could vary the conditions governing

the scaling processes either by decreasing or worsening the

problem.

In this paper, a study of such evolution is made by the

treatment of the output behavior of the first and best

producing well in the Miravalles geothermal area.

Both physical and chemical data available are presented

here to show whatever possible trends may be occuring under

continuous production of the well.

It is not the scope of this work to present a "magical"

solution to the calcite scaling problem, but rather to try

to understand the mechanisms that control it. The aim is to

elaborate a simple reservoir model of the field that may

provide the solution of the problem in the near future,


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2. THE MIRAVALLES GEOTHERMAL FIELD

The Miravalles geothermal area is characterized by strong

fumarolic activity, hot springs and rock hydrothermal

alteration. The area is located in the south-western slope

of the Miravalles volcano which is a part of a chain of

quaternary volcanoes known as the Cordillera de Guanacaste.

The Cordillera trends north-west to south-east and is

flanked in the south-western part by a disected plateau

composed of tertiary volcanic and sedimentary rocks overlaid

by quaternary tuffs and sediments. The geographic location

of the Miravalles field is shown in Figs. 1 and 2.

On the edge of the Miravalles volcano, there is a

geologic feature known as the Guayabo Caldera, which has

apparently been the site of lakes in the past. Its fertile

soil is dedicated to agricultural activity. In part, the

caldera has been buried by volcanic materials.

The first investigations on the potential of the

Miravalles geothermal field for electric power uses were

carried out almost 20 years ago. In 1974, the Instituto

Costarricense de Electricidad (ICE) carried out an extensive

investigation of the geothermal area, which included the

following :

-Surface geological reconnaissance


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-Chemistry of waters and gases from hot springs

and fumaroles

-Geothermal gradient measurements

-Regional gravity surveys

-Electrical resistivity surveys

-Regional geohydrology

-Microearthquake detection and ground noise

measurements

At the end of these studies, a report was published (ICE,

1976) with recommendations to extend the exploration and to

drill three deep exploratory wells. The wells were located

one to three km away from the area of fumarolic activity and

in the center of an area characterized by high geothermal

gradients at the surface (200 to 500 'C/km) and low

resistivity values (5-10R-m) at depths of 500 to 800 m.

Fig. 2 shows the area of investigation and some of the

results.

The results obtained from the different exploration

techniques agreed on the existence of an anomalous zone of

about 4 sq. km in area. In addition to the high geothermal

gradients and low resistivity values, the geothermometry

from hot springs and fumaroles showed values of the order of

24OoC. Gravity surveys showed the existence of a graben


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structure that may contain the geothermal reservoir; and the

microearthquake studies, although still incomplete, showed

active fault movement in the area.


3. DRILLING AND COMPLETION

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The drilling of the first geothermal well in Costa Rica

was carried out with an IDECO-H525-D rig, with a depth

capacity of 1,500 m when using 3 1/2 inch drill pipe. The

drilling started on April 1st. 1979, and was completed on

July 28th. 1979.

The well design and the lithology encountered are shown

in Fig.3. It shows the various casing and hole diameters

and the depth at which the transition between the 7 5/8"

slotted liner and the 9 5/8" production casing occurs, which

corresponds to the point where the calcite problem was found

to be most serious.

The drilling program is shown as Fig.4. A good percentage

of the 4 month period was used for either logging the well

or running production tests. Since this was the first well

to be drilled, it was thought desirable to obtain the

greatest amount of information at all the stages. For this

reason, whenever an important loss of circulation was found,

the drilling was immediately stopped. A lighter drilling

mud was circulated, and a recovery temperature survey run.

When the temperature recovery was fast a further

investigation was carried out by stimulating the well into

production and measuring the output. This technique, even

though slow and expensive, permitted the location of two

important production zones at 304 and 925 m. The first zone


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was cased off due to its limited potential and shallow

depth, while the second zone is believed to be the major

feed zone of the well (ICE, 1980).

On August 28th. 1979, the well was

first time and its total production est imater d to be 79 kg/s

using the lip pressure method. The

discharge for 3 days.

flow

well

tested for the

was kept on

The temperature recovery of the well from. surveys carried

out before and after the first flow test is shown in Fig.5.

In this figure the curve for September 7th. 1979, shows a

temperature reversal at a depth of about 900 m even though

the measurement was carried out after the first 3 three day

flow test.


4. PRODUCT1 ON HI STORY

After the first production test in August 1979, well

PGM-1 was tested several times for short periods of 2-3 days

for output measurements and sample collection. The output

was measured by the lip pressure method (James, 1975).

Three long term flow tests were carried out on PGK-1.

Table 1 shows the dates, the production (output) and the

wellhead pressure at the beginning and end of each of the

periods.

The ratio of (total production)/(wellhead pressure) is

shown in Fi.6 for the three test periods. It can be seen

that this ratio was almost constant regardless of the

scaling problem in the wellbore. The wellhead and total

flowrate are shown in detail for each of the test periods as

a function of time on Figs.7, 8 and 9.

The equipment used for flow measurements in tests periods

2 and 3 is shown in Fig.10. During test period 3 the well

production output was monitored continuously by recording

the wellhead and lip pressures, as well as the water flow

rate that separated in the silencer. A diagram of the

equipment used for continuous recording is shown in Fig.11.


4.1 Flow test period 1

-9-

The first two test periods were carried out without any

flow restriction in the wellhead. During the first of these,

the calcite deposition problem was discovered. ~ig.7 shows

the rapid decline of both the pressure and the flowrate for

this test.

At the end of flow test period 1, some calcite deposits

were discovered on the surface of a temperature instrument

that had been lowered in the well. It had not been possible

to lower the instrument deeper than 900 m due to a

restriction in the wellbore. Also, particles found on the

floor of the muffler structure were analized in the

laboratory. Table 2, shows that the particles were 89%

calcium carbonate (ICE, 1981).

On May 1st. 1981, well PGM-1 was killed by gradually

increasing the flow of cold water, on Kay 21st, a caliper

log was run in the well (Gearhart-Oven continuous recording

three arm caliper tool). The results of the caliper are

shown in Fig.12. A reduction in diameter was located at a

depth of about 870 m from the original diameter of 177 mm of

the slotted liner, to 88.9 mm. The diameter had therefore

been reduced a maximum 50% and the cross sectional area by

almost 75%. The maximun reduction occur some 20 m below the

liner hanger depth of 845 m and some 11 m above the point

where the slotted liner starts. In well PGM-1 there are four

joints of blind liner of 7 7/8" connecting the liner hanger

to the slotted pipe. A similar situation was detected in

well PGM-3 which however had been producing for a shorter


period of time.

4.2 Flow test period 2

After the caliper logging period, the well was allowed to

warm up and a new period of flow testing began in June 1981.

This test was carried out to follow the production and

pressure decline for a longer period of time. As in test

period 1 the well was discharged without a pressure

restriction at the wellhead.

The total flow rate and wellhead pessure of well PGM-1 in

the flow test period 2 is shown in Figs. 8 and 8A. It can

be observed that the production decreased from 67 kg/s in

about a thousand hours and suddenly increased to a value of

48 kg/s after a maximum discharge pressure measurement had

taken placerwhere it leveled until the end of the test. The

production values were obtained by the lip pressure method.

4.3 Cleaning operation

On November 6th. 1981, well PGM-lwas shut in and killed

again with cold water from the top. It was not possible to

run another caliper log because the calcite obstruction had

increased to a point where it would be dangerous to loose

the tool in the well..

The cleaning procesg, took a longer time (approximately


-11-

120 days) than expected because it had to be done with a

cable tool rig (the only machinery that was available

locally). The cleaning operation stopped at 898 m depth,

well below where maximun calcite deposits had been detected.

A caliper log revealed that the well had been thoughroughly

cleaned.

4.4 Flow test period 3

The third test was started on March 3rd. 1982, and lasted

6 months, during this time the production was monitored

continuously. And every two or three weeks a direct

measurement of the well production was carried out with a

60" (diameter) WKM flash separator after which the separated

brine and steam flowrates were measured through orifice

plates. The advantage of this method is the possibility of

comparing the results with the lip pressure method. Usually

the output curves measured by the two methods agreed within

a range of 10%.

Flow test period 3 is the basis of the data interpreted

in this report. The third test period is important because

the well had been cleaned of the deposits that built up in

the first and second tests. The well was therefore in a

"like-new" condition at the beginning of the test.

The measurements in flow test period 3 proved to be very

useful in following the evolution of the well


-12-

characteristics regarding production and chemical changes

with time. After about 200 hours from the beginning of the

test an orifice plate was inserted at the wellhead to

restrict the flowrate. The plate was sized to maintain the

pressure near the maximum discharge pressure of the well at

the beginning of the third test period.

During the direct flow measurements (every 2-3 weeks) and

chemical sampling the procedure was to start the

measurements at a pressure equal to or near the long term

(restricted) wellhead pressure. Then to gradually lower the

pressure and increase the flowrate. At every point the

production performance and chemical samples of the brine,

steam condensate and non-condensable gases were obtained.

All the measurements performed during this test period,

had been tabulated and plotted, and they are shown in Tables

3 through 11, and 15 through 23 and on Figs. 9, 14, and 15

through 43.


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5. ANALYSIS OF PRODUCTION MEASUREMENTS

The decline in wellhead pressure and flowrate in the

three test periods art shown in Figs.7 to 9. The flowrate in

test periods 2 and 3 is also plotted against cummulative

production in Figs. 13 and 14. There is one aspect of these

output curves that the three test periods have in common;

the ratio of (total production/wellhead pressure) is

constant in each flow test period as shown in Fig.6. The

significance of this observation is not clear, but it may

result from a constant flashing level in the wellbore.

In flow test periods 1 and 2 the flowrate decreased

rapidly initially, exhibiting a concave downward behavior as

shown on Figs.7 and 8. This behavior may be characteristic

for wells that suffer calcite deposition in the wellbore.

In flow test 2, a sudden increase of the well flow rate

occurred after about 2000 hours and 3000,000 tonnes of

cummulative production as shown in Figs.8 and 13. This may

have been caused by a maximum discharge pressure test that

was carried out at that time. On the next day the records

showed a higher wellhead pressure and flow rate.

In flow test 3, since the flow was restricted at the

wellhead , it was expected that the well would deposit less

because of the high pressure and low flow rates. Fig.14

shows that this was true. However, a very slight decline was


visible either to a slow rate of deposition or that the

cross sectional area had not been reduced to the critical

point when rapid decline occurs. As it will be shown later,

the precipitation of calcite tends to decrease when the well

is operated at higher pressures.

From the several deliverability tests (flowrate and

enthalpy against wellhead pressure) performed during the six

months of test period 3, it is clear that the productivity

of the well kept decreasing all the time. In Tables 3

through 11 and Figs.15 through 24 the different

deliverability tests carried out are shown. In Fig.24 four

of these tests are plotted together and compared to a test

of October 1980 when the well was clean. The test of April

25th. 1982 shows some scale buildup. At two months (57 days)

after the cleaned well was restarted. Fig.25 shows the

flowrate decrease with time at a separation pressure of 7.5

kg/cm2 (abs) probably caused by the scaling process.

For each specific test the enthalpy was calculated for

downhole conditions. These are shown in Table 12 and plotted

with the deliverability curves in Figs.26 through 34. This

is the enthalpy of the two phase mixture at the surface.

The enthalpy has, shows a shift either to higher or lower

values in some of the tests. This is especially true for

high pressure points. This anomaly can perhaps be explained

by looking at the test procedure that was followed. The

first point of the test is usually the one nearest the


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pressure that the well was at that specific day. Then the

flow was changed to get the next point and so on until the

lowest point was reached. The time between points is nearly

an hour while the well stabilizes its flow at a given

pressure. It is true that any change made at the surface is

also a change in the heat flow regime to or from the well

and the formation. It is unlikely that one hour will

stabilize the heat loss (or gain) to a point that stable

values of enthalpy can be obtained. This holds particularly

true for low flow rates and high wellhead pressures.

Therefore, the values obtained for enthalpy can be

approximated for qualitative purposes, rather than for

quantitative ones. However, some points tend to deviate

more from the mean values than others, usually the last

point. For this reason it would be acceptable to think that

if all the tests are performed in a similar way, using the

same instrumentation and personnel, such deviation should be

the same for every measurement.

Fig.35 shows the mean enthalpy values versus time and the

standard deviation for each point without dropping any

offset value. Fig.36 shows the same points and the

correspondent standard deviation adjusted by dropping the

most offset value (when necessary). In this plot it can be

observed that the deviation is almost constant to every

point. It is also important to see from this plot that the

least square fit through all the points shows a tendency of

the enthalpy to increase with time. The same behavior was


-16-

observed by James (19811, McNitt, (19811, and by McNitt et

al. (1983).

Another possibility could be a tendency to flash in the

formation rater than in the wellbore, therefore a constantly

increasing steam fraction would be produced with the

correspondent increase in the enthalpy value. This theory

would suggest the possibility of a two phase zone (water and

steam) that develops with the long term tapping of the

reservoir fluids.

A possible explanation for this phenomena is the entrance

of hotter fluids coming from a deeper and hotter source thus

increasing the enthalpy value. This idea seems realistic

since the enthalpy increment rate is small but constant.


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6. WORLD EXPERIENCE OF CALCIUM CARBONATE DEPOSITION

Calcium carbonate deposition in geothermal wells has been

studied in countries where the problem has appeared, either

in the early stages of the field's life or where it has been

a persistent problem throughout the production history of

the field. Different techniques have been developed in

order to cope with the problem (New Zealand, Iceland, Turkey

and Mexico) and perhaps the experience accumulated in those

countries is the most valuable source of ideas and solutions

one can look at when dealing with the problem.

In looking to these experiences, it is worthwhile not

only to consider for calcite deposition, but also silicate

deposition, since both problems may be present at the same

time and may have a similar approach for remedial actions.

In Table 13 such problems have been divided into three

categories:

-Major calcium carbonate deposits

-Minor calcium carbonate deposits

-Complex deposits

The following quote is from the same reference and it is

reproduced here to give an idea about the magnitude of the

problem:


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"Several physical and chemical processes occur

as high temperature water is brought to the

surface through wells and by pipeline into surface

equipment. A steam phase forms in increasing

proportion as pressures decrease along the

pipeline and it contains a large proportion of the

gases originally present in the deep water. The

cooled water is depleted in acidic gases, while

non-volatile constituents undergo concentration.

Mineral deposition may be initiated by these

changes.

A small change in the concentration of a

constituent can represent a sizable deposition

rate in a geothermal well of high output. For

example, a loss of 1 ppm of calcite or silica from

solution in a 20 cm diameter well producing 100

tons of water per hour would give a deposit about

2 mm thick per day over a 1-m length of pipe.

Deposition rates can be much greater than this.

For example, a well in the Tongonan, Leite,

Philippines, area developed aragonite scale at the

rate of 1 mm/h (R. .B. Glover, personnal

communication). Complete blockages of wells have

occured in a matter of days in severe scaling

situations"


-19-

The experience in New Zealand, in the field of Kawerau

shows that the most satisfactory method for calcite removal

is by mechanical reaming. A Failing rig is used to do this

work and in some cases, full productivity of the well is

regained after the operation has been carried out, as was

the case of PGM-1. This infers that the largest bulk of

calcite formed during production occurs in the well casing.

The frequency of reaming is dependent on the nature of the

system, but in the case of Kawerau, it has been found

necessary to clean most wells anually. Acidification was

also tried once in a well in Kawerau with severe damage

caused to the casing by the action of the acid. This results

from the lack of a sufficiently stable inhibitor, capable of

maintaining its properties at high temperatures for a period

of time long enough to allow the complete removal of calcite

(Mahon, 1981).

In Iceland, in the Svartsengi field, a more sophisticated

rig has been tested to clean the wells from its calcium

carbonate deposits while the well is flowing and discharging

the drill-cuttings. In this case, a WABCO 2000 rig was used

with a Grant rotating head, blow out prevention equipment

and a specially designed apparatus that cools the head's

rubber stripper. The first test of the rig proved that the

proposed work procedure and equipment worked (Arneberg,

1981). Other simpler methods have also been used with

success in Svartsengi and other fields in Iceland.


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In Mexico, the removal of silicate deposits from the

wells at the Cerro Prieto field, is often done by mechanical

reaming.

In the state of Nevada, in a well in the Desert Peak

geothermal area, a very innovative method of injecting C02

in the brine before its flashing depth is reached, yielded

positive results by reducing the amount of calcite deposits

in the well during the one month period of the test (Kuwada,

1982 1.


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7. CALCIUM CARBONATE CHEMISTRY

Calcium carbonate deposition occurs due to a set of

geological, physical and chemical conditions that are

encountered at a given time in a geothermal reservoir.

Geological factors such as groundwater circulation and

mineral composition of the reservoir rocks are important in

understanding the origin and mechanisms governing the scale

forming processes. Physically, the pressure, temperature

and amount of the non-condensable gases and the kinetics and

shape of the calcite deposits are of great importance

(Mahon, 1981).

The geothermal fluids at Miravalles contain sufficient

dissolved gases to increase the pressure at which flashing

occurs by a considerable ammount. When the fluid pressure is

near the flash level, particularly if C02 is present, the

start of the flashing is accomplished by a shift in pH as

the carbonate solution equilibrium is unbalanced by the

release of the gaseous phase of C02. The fluid becomes then

supersaturated with respect to carbonate as the pH continues

to rise, and the calcium present will trigger a

precipitation reaction depositing calcium carbonate on the

walls of the wellbore.

This mechanism may be still more favored if a sudden

increase in the diameter of the well (i.e. a liner hanger)

is present. Therefore, transitions in the casing diameter


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should either be avoided or located at a safe distance above

or below the predicted flash horizon.

There are other reactions that have some influence in the

solution pH, such as the amount of H2S in solution, but for

the purposes of the brine that is present in the Miravalles

reservoir, their contribution is very small,

The flashing point also depends on the partial pressure

of the other gases, besides C02, present in the brine; but

those gases are less soluble than C02 by a factor of nearly

20, and therefore, their effect on the bubble point of the

solution is minimum and it will depend largely on the amount

of C02 present in the solution (Michaels, 1981)

Experimental evidence indicates that the reactions

producing scale can be very rapid, occuring in fractions of

a second, following the creation of oversaturated

conditions. The carbonate scale usually forms as the

mineral calcite, but under some conditions, the mineral

aragonite, which has the same composition as calcite, but

with a slightly different crystal structure, may

precipitate. For all practical purposes, both minerals can

be considered identical (Michaels, 1980).

Calcium carbonate deposition from individual waters vary

from field to field, but the typical reaction can be

represented by the following formulation:

C02(aq) = C02(vap). . . , (EQILIBRIUM)


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HC03- + H+ = CO2(aq) + H20 ...... (FLASHING)

Ca2+ + 2HC03- = CaC03 + C02(aq) ..... (DEPOSITION)

It is interesting to notice that in the earlier stages

previous to flash, Ca ions are more abundant than C03 ions;

later, C03 ions are more abundant than Ca ions. Calcite

will form in the first instance, but not in the second,

despite the presence of both an adequate thermodynamic drive

and a reasonable supply in Ca (Michaels, 1980).

In practice, the calcite deposits may occur in the first

20-25 m above the first boiling point. The deposition shape

may tapper off from this point and become almost zero. By

controlling the wellhead pressure, the deposition can be

controlled in such a way that it occurs within the pipe at a

choosen level.

Following an extensive withdrawal of water from a high

temperature aquifer, a general depletion of carbon dioxide

in solution may occur through boiling. The reaction of the

water with the rock minerals is not rapid enough to

equilibrate the rise in pH, favoring the calcite to

precipitate in the formation pores and fissures. This,

however, may be of little importance if it takes place

homogeneously, but if the deposition occurs in a major

contributing fissure, an irreparable decay in flow may occur

(Ellis and Mahon, 1977). The problem may become more severe

if the reservoir fluids are rich in C02 and if the

productivity of the rock is inadequate to fill the wellbore.


-24-

Nancollas and Reddy (1974), conducted a series of

experiments that measured crystal growth over a wide range

of stirring rates. Their conclusion was that the rate of

crystallization is independent on the fluid dynamics of the

system. Therefore, it can be expected that the rate of

scaling would be very little affected by factors such as

flow velocity of the loaded aqueous phases over the scaling

surfaces, unless some other factor like erosion over the

soft deposits takes place.

It is difficult to determine whether or not a fluid from

a specific reservoir will scale during production. The

difficulties are compounded by the fact that conditions

frequently encountered downhole, such as high temperature

and pressure, can not be easily simulated in the laboratory.

Sampling of an aqueous solution brought to the surface for

analysis can give entirely misleading results owed not only

to changes in the original enthalpic conditions, but also to

the fact that the solution may be actively depositing scale

minerals within the well. For this reason, it is extremely

important that the data obtained be consistent with

standardized procedures used in other fields in the world,

for comparative purposes.


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8. CHEMICAL SAMPLING AND ANALYSIS

8.1 Sampling and analysis methods

For flow test periods 2 and 3, the equipment for

separation and sampling of steam and water shown in Figs.10

and 11 was used. Samples of brine, steam condensate and non-

condensed gas were taken. The steam flow sampled was cooled

in a bath of running water before passing through the

condensing coil. The non-condensed gases were drained at the

outlet of the coil from a flask that contained both

condensed steam and gases. All equipment was flushed for a

given time before the sample was taken.

Since it is easy to control the separation pressures by

using the control valves, four samples were taken at each of

the five or six pressure points of the test, giving a total

of 20-24 samples analyzed for each test.

In every sampling point, distilled water was used for

washing the bottles. In the case of the water samples, the

bottles were also flushed with the brine flow before taking

the sample. Care was especially taken with the gas flasks,

to avoid air contamination. The samples were packed and

sent to ICE’S laboratories in San Jose. The chemical

analysis were done by using atomic absorption or gas

chromatography.

8.2 Chemical Analysis


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When sampling geothermal wells the components of the

steam-water mixture are usually sampled after the it has

passed through the flash separator. This method makes it

difficult to define the state of the carbonate system in the

deep water or in particular to calculate the carbonate

equilibrium. Computer codes are available to simulate

downhole conditions in geothermal wells (EPRI, 1978,

Arnorsson, 1982). They iterate solubility data for selected

geothermal minerals in order to facilitate the evaluation of

solution/mineral equilibria and chemical speciation.

(Arnorsson, 1982).

The use of two computer codes working with the same data

will be analyzed in a separate chapter. The data available

for the tests made on June 2nd., June 24th. and August

8th.,1982 performed in PGM-1 are shown in Table 14. The

separation pressure is known only for the samples of test

periods 2 and 3. The brine composition is adjusted to

wellbore conditions by knowing the steam and liquid

fractions at each sampling point. The values of the brine

for tests 2 and 3 are plotted against the time in hours

since the well was first flow tested on August 27th. 1979.

These plots appear in Figs.37 thorugh 42. In each of these

figures the gap between 18,400 and 23,600 hours corresponds

to the period of well cleanup . Fig.43 shows the Na/K ratio

versus time for the same samples. In Table 15 a more

detailed analysis for four points of the third flow test

period are shown. Special attention should be given to


-2 7-

Figs.40 and 43 since the decreasing values with time of Na/K

may indicate an increase in temperature of the reservoir

fluids (Fournier, 1981). The chloride increase with time

observed in Fig.40 may also be indicative of fluids of

different (higher) temperatures entering the wellbore. Both

tendencies are supported by the increase in enthalpy

discussed earlier and shown in Fig.35.


9. DEPOSITION ANAL1 SI S

-2 8-

9.1 Electric Power Research Institute Program

The Electric Power Research Institute computer code

EQUILIB, reproduces the equilibrium chemicai composition of

gas, liquid and solid phases of an aqueous solution

consistent with the physical laws of balance (EPRI, 1978).

The physical laws obeyed in the computations are elemental

mass conservation, charge neutrality and Gibbs free energy

minimization. The equilibrium data base used in the

calculations contains 8 gases, 200 aqueous species and 187

solid mineral species from 0 to 300 'C.

The EQUILIB code consists of "n" equations in "n"

unknowns where "n" can be a very large number. Depending on

the complexity of the brine, solution of up to 300

simultaneous equations may be required. The algorithm used

for the solution of the matrix uses an iterative procedure

to improve an initial estimate of the solution in sequential

calculations until all of the equations are satisfied,

within selected limits (Roberts, 1983).

When the input has been supplied to the codef the

subprogram EQUILIB-A calculates the equilibrium constants

for the data. A temporary data base addition provides

equilibrium constants for C02, HC1, 02 and H20 as functions

of respective concentrations in the liquid phases. Another

subroutine called GEOTHRM-2 in turn retrieves the


initialized data from the disk and calls for EQUILIB-B to

solve the problem. After the problem has been solved the

subroutine GEOTHRM I11 provides the output (EPRI, 1978).

The input data for the EQUILIB code are given in Table 24

and the output of mineral precipitation is shown in Table 25

for four different runs. The results of the fourth run with

the EPRI code which contained the temperature values

calculated for each test by geothermometry, are plotted in

Figs.44 and 45.

The most important feature of the results obtained is

that in all four runs the calcite values tend to decrease

with time, which was suspected earlier with the increase of

reservoir enthalpy and geothermometry. Excess quartz, was

also expected to increase in value if hotter fluids were

being withdrawn from the reservoir at the end of the test.

From the plots shown in Figs.46 and 47 this can be observed

for wellhead pressures od 7.5, 10 and 12.5 kg/cm2.

Another important characteristic is that the amount of

excess quartz and calcite in the solution is greater at

lower pressures and has the tendency to decrease as pressure

increases. This fact should be taken into account when the

operation of the field is to be started since this will

influence the turbine and separation equipment design. It

will also influence the flashing point of the brine in the

well.


-30-

9.2 National Energy Authority (Iceland) Program

The data that was used in the EQUILIB code was also fed

into the WATCH code develop at the National Energy Authority

in Iceland (Arnorsson et al. 1982 and Svavarsson 1981). This

data appears in tables 16 through 23 and corresponds to

analysis from samples taken at two different wellhead

pressures on June 2nd. and June 24th. 1982 and four

different wellhead pressures on August 12th. 1982. This

code works in a slightly different fashion than the EQUILIB

code but basically the output is the same. The program is

also written in Fortran IV language and the method of

solution is very similar. The calculations are based on the

mineral concentration of the water and steam phases and the

discharge enthalpy, which determines the proportion of the

phases in the flow.

The program can also be used to calculate speciation in

water and steam-water mixtures which have boiled

adiabatically in one stage to specified sets of temperature,

and then cooled down without steam loss to another set of

temperatures. These calculations are useful in evaluating

how boiling and cooling causes the water to depart from

equilibria with specific minerals.

All calculations can be carried out at any specified

temperature within the range of 0 to 370 C. All the

chemical components that occur in major concentrations in

geothermal waters and/or rocks commonly found in geothermal


-31-

systems are included in the program as well as 65 reactions

describing equilibria between 73 aqueous species and 7

gases. Solubility data of 26 commonly occurring geothermal

minerals are also incorporated to facilitate the comparisson

between water chemistry and mineral solubility (Arnorsson,

1982 1.


9.3 Rice University Method

-32-

A field engineering method to predict calcium carbonate

deposition was developed by Odd0 and Tomson (1982). This

method uses commonly measured field parameters and has been

tested for geopressured brines with very interesting

results.

The method calculates the saturation index (Is) and the

pH by using conditional equilibrium constants dependent on

temperature, pressure and ionic strenght, which eliminates

the need for activity coefficients. The method calculates

the Is following the Stiff and Davis (1952) method, but

makes possible an approximation of pH values if they are

unknown. The great advantage of it is that it is relatively

easy to use if total calcium, bicarbonates, pressure,

temperature, dissolved solids or conductivity values and

the mole fraction of C02 in the gaseous phase are known.

Since all these parameters are usually analyzed in

geothermal wells, the method becomes a very useful tool in

the field laboratory because it can also be used to

calculate the brine equilibrium in the surface equipment by

simply varying the conditions accordingly.

Since our data contains all the necessary information

required for this model, the method was handled in the same

way that was presented by Tomson (1983). As with the

computer models, the same values for reservoir temperature

were used from geothermometry calculations. In Table 26,


-33-

the input data for this model is shown as well as the

results. The values for the three tests are plotted versus

wellhead pressure in Fig.48. The similarity of this plot

with the results obtained by the EQUILIB method reveals that

for qualitative purposes the method can be used.


10. FLASHING POINT

The data for test period 3 was also analyzed with a two

phase flow simulator developed by Ortiz (1983). This method

has the flexibility of working with either conditions at the

wellhead (temperature, pressure, deliverability, flowing

enthalpy) or with downhole conditions (reservoir pressure,

temperature and enthalpy) for up to five different diameters

of the pipe.

The output of the program displays the pressure,

temperature, and fluid velocity profiles for both the single

phase and the two phase regions of the well and predicts the

depth of the flashing point for the given set of well

flowing conditions.

For our purposes, the raw data that appears in Tables 15,

17, 20 and 23 was fed into the program and the results

obtained from it as for the depth of the flashing point at

each wellhead pressure (assuming no scaling in the well),

are plotted in Fig.49.

It is difficult to believe that the flashing point will

migrate almost 1300 feet in a 6 month periodas indicated in

Fig.49. The approach followed then, was to take the

reservoir conditions for the earliest flow test performed

after the clean-up operations of the well, which corresponds

to April 29th. 1982 and assume the well completely free of


scale at this point.

The reservoir conditions for a clean well were obtained

from the program for three different wellhead pressures by

feeding it with surface data. Then, for each of the three

wellhead pressure points reservoir conditions were kept

constant as well as the flow rate in the surface but the

diameter of the well was changed.

Since the wellhead pressure during the long term test

oscillated around 10 kg/crn2 (with the orifice plate

restriction at the outlet) it seems reasonable to assume

that the flashing depth had to be between 2125 and 2075

feet. Fig.50 shows for the deliverability test (clean well

conditions) carried out on April 29th. 1982 the conditions

that were assumed to take place during the whole 6 month

test. If the flashing point is assumed to remain unchanged

(or at least within the ranges specified in Fig.501, it is

expectable that the calcite deposits will develop at that

depth too. Therefore, the conditions for the diameter of the

well as shown in Fig.51 were used to simulate the wellhead

pressure decrease that would occur by choking the well over

a lenght of 50 feet at the flashing point depth with calcite

deposits, while holding a constant flow at the surface for

each wellhead pressure. The three wellhead pressure points

that were chosen from the test of April 29th. 1982,

correspond t o low, intermediate and high pressure and flow

rates.


The program was run many times for each flow rate

condition, starting with the clean condition of the well and

ending where the well was not capable to sustain the flow

rate specified. Tables No.27 through 29 show the area

decrease and the corresponding wellhead pressure obtained

for the low, intermediate and high flow rate values. For the

case of the intermediate flow rate, more points were

obtained in order to observe the pressure decay point more

accurately.

In Fig.52, the simulated well performance curves obtained

through this method are shown for four different choked

diameters. Then, the next step was to plot on top of those

simulated performance curves the real ones, and in Fig.53

this situation is reproduced, for the deliverability curves

of Jun. 2nd. and June 26th. 1982 . As can be observed, the

well was able to go in August 26th. 1982 far below the last

simulated curve (which stands for the lowest flowing

conditions that was possible to maintain for the proposed

mode 1.

By repeating the same procedure to different wellbore

deposits conditions one should be able to obtain a more

accurate result. The results obtained here are shown only

with the purpose of information, but it is beyond the scope

of this work to obtain the optimum model which can be

probably done by a trial and error procedure.


-37-

Fig.54 reproduces the values of wellhead pressure versus

the choked pipe area obtained from Table 28 for intermediate

flow rates. As it is expected, the wellhead pressure decay

is almost imperceptible at the beginning and very fast at

the end, where the percent of area changes very quickly with

small changes in diameter.


11. REMEDIAL ACTIONS

The effect that well scaling will have On the future

development of the Miravalles geothermal field, Will depend

on the feasibility of solving the problem. Many methods

have been suggested to minimize and/or control the Scaling

problem (McNitt et al. 1983). The methods can be divided as

follows:

1. Periodic cleaning by the mechanical method of drilling

out the calcite

2. Periodic or continuous suppression of scale by chemical

or CO2 gas injection

3. Minimizing deposition of scale by operating the wells at

a relatively high wellhead pressure, thereby insuring

flashing above the casing-liner joint

4. Minimizing scaling potential by running the same diameter

liner from production depth to the wellhead

5. Avoiding scale by finding zones in the reservoir from

which non scaling fluids can be produced

Among those methods suggested, the mechanical cleaning,

together with running a single diameter in the well and a


-39-

further investigation searching for a deeper and hotter

source of the reservoir, will probably minimize the problem

during the exploitation of the field.

The inconvenience of using some of the most recently

developed methods, is that those methods have been tested

for short terms and would be applied still under a testing

basis in the Miravalles field.

Instead, a combination of mechanical cleaning and well

design improvement are techniques that have been used

elsewhere and do not involve the use of any sophisticated

methods. Increased well diameter has reduced frequency of

calcite cleaning in the Svartsengi field in Iceland

(Gudmundsson, 1983) If carried out with good organization,

it may provide the less costly method that can be applied in

the field, especially under a combined condition of lack of

specialized equipment, manpower and spare parts.

The last option contemplated, of extending the

exploration elsewhere in the field, is strongly supported by

some of the findings of this work and the possibility of

having either an offset or deeper hotter aquifer is quite

good.

11.1 Mechanical Removal

The mechanical removal of calcite deposits seems to be

widely used in areas where the problem has appeared. Mahon


-40-

(1981) states that the use of a Failing rig to remove

calcium carbonate in the field of Kaweraw, New Zealand, is a

common practice. Similar reports from Iceland and Mexico are

known. In the field of Svartsengi (Iceland) and Cerro

Prieto, (Mexico), a more useful technique have been

developed for scale removal by rotary drilling while the

well is producing.

The two techniques that are being used are similar and

the main difference is in the place where the cooling of the

packer that seals against the drill string takes place and

the type of pipe joint used. In the Mexican method, upset

joint, 3" drill pipe is used. Two blow-out preventors are

used, and the cooled drill pipe packer and flow diverter

spool make the height of the substructure almost 30 feet.

The coolhead used in one of the methods employed in

Svartsengi and shown in and shown in Fig.57 seems to offer a

good solution for this inconvenience. Both systems have the

advantage of being able to carry out the whole operation

without exposing the well to thermal shock, either from

warming up or cooling down periods that, when done

repetitively may cause damage in the casing.

11.2 Running Liner to Wellhead

It is likely that the scaling rate can be reduced by

having a uniform diameter from the bottom to the wellhead.

In Cerro Prieto, Mexico, the use of the Hydrill, Super-Flush


-4 1-

joint in 9 5/8" diameter liner, that is cemented to the top

of the reservoir through the use of cementing ports, has

reduced greatly the silicate deposition in the wells. This

type of pipe joint, oposite to the buttress joint, is

internally continuous and leaves a smooth surface in the

joint area.

The use of the technique of cementing through portholes,

provides thus, a smooth pipe of a single diameter from the

reservoir to the wellhead. An increase in production has

also been obtained with this method as compared with the

conventional one, since the 9 5/8" diameter can carry a

bigger production with less pressure losses (Guiza, 1983).

This approach reduces the scaling rate but does not

eliminate it.

11.3 Well Location and/or Deepening

It is common that wells form scale in the wellbore when

they are located peripherically with respect to hotter

regions of a reservoir. In Miravalles, the possibility of

deepening at least one of the existing wells is worth

consideration, since the liner hanger may be still in

operable condition to be retracted.

Another possibility would be to explore with deep

gradient surveys and resistivity soundings in the less

explored zone uphill the Miravalles volcano as suggested by


McNitt et al. (1983).

-42-

The data that has been analized in this paper, strongly

supports this possibility.


12. CONCLUSIONS

1. The results obtained through the study of the

chemistry and deliverability in the second and

third flow test periods , seem to indicate a

possible evolution of the field, that suggests the

possibility of withdrawing in future from hotter

aquifers that may feed the wells after prolonged

periods of time.

2. Such evolution is shown in this paper starting with

indications from the chemical analysis and

production measurements, and supported with

calculations from geothermometry and computer

models.

3. Using the two phase flow simulator to reproduce the

scaling process in a cleaned well, appears

promising. The simulator can perhaps be changed to

suit deposition problems or by matching the

solutions by trial and error methods.

4. From all the parameters analyzed in this study,

careful measurements of the production and

chemistry of the liquid and gas phases seem to be

important when using the computer codes available.

It is equally important to gather as much data as

possible under pre-planned schedules in order to

use, if possible, statistical analysis.


-44-

5. The use of a simple and qualitative method for the

prediction of calcite precipitation is presented

and seems to work well as the more advanced methods

for the data studied.

6. Mechanical reaming of scale deposits and improved

well design have proven to be effective over long

periods of time in other parts of the world. It

appears to be a workable solution to this important

problem.

7. Deepening of the existing wells, for investigation

purposes, or extension of the geophysical studies

searching for a hotter source, and therefore, a

less scaling environment is recommended.


1.

2.

3.

4.

5.

6.

7.

8.

9.

-45-

REFERENCES

Arneberg, J. E.: "Testing of Equipment for Use in

Connection With Workovers in Flowing Geothermal

Wells". Paper in preparation. JEA-81-01, Iceland,

1981. sk.

Arnorsson, S. : "Mineral Deposits from Iceland

Geothermal Waters ,Environmental and Utilization

Problems". Society of Petroleum Engineers, 7890,

1979. sk.

Arnorsson, S., Svavarsson, H.: "The Chemistry of

Geothermal Waters in Iceland. Calculation of

Aqueous Speciation from 0 to 370 C". Geochimica et

Cosmochimica Acta, Vol. 46, No.9, Sep. 1982.

Ellis, A. J., Mahon, W. A. J.: "Chemistry and

Geothermal Systems". Energy, Science and

Engineering: Resources, Technology, Management -

Academic Press. Belton, Texas, 1977.

EPRI : "Brine Chemistry and Combined Heat/Mass

Transfer". Interim Report ER-635, Vol. 1, 1978.

Fournier, R. 0.: In. Ribach L:, Muffler, L. P. J.:

"Geothermal Systems: Prlnciples and Case

Histories". John Wiley and Sons, 1981.

Grant, M: , Donaldson, I, Bixley, P. "Geothermal

Reservolr Engineering". Energy, Science and

Engineering: Resources, Technology, Management.

Academic Press, Belton, Texas, 1982. ,sk

Guiza, J.: Instituto de Investigaciones Electricas

(IIEE), Cerro Prieto, Mexico. Personal

comunication, 1983.

Instituto Costarricence de Electricidad:

"Prefeasibility Report of the Miravalles Geothermal

Area". Internal Paper, 1976.

10. Instituto Costarricense de Electricidad: "Drilling

and Production Report for Wells PGM-1, PGM-2 and

PGM-3". Internal report, 1980.

11. Instituto Costarricense de Electricidad: "Summary

of Investigations and Technical Findings as of

November, 1980". Internal report, 1981.

12. Instituto Costarricense de Electricidad: "Results

of the Tests Carried Out in Wells PGM-1, PGM-2 and

PGM-3 of the Miravalles Geothermal Project". Doc.

1006-81. Oct. 1981.

13. James, R.: "Measurement of Steam-Water Mixtures

Discharging at the Speed of Sound to the

AtmosDhere". New Zealand Eng. Jour., Vo1.2, Part 2,

1976


-46-

14. James, R.: "Report on Study of Miravalles Wells".

Dep. of Sci. and Ind. Res., Wairakei, New Zealand,

June, 1981.

15. Mahon, W. A. J.: Dep. of Sci. and Ind. Res.,

Wairakei, New Zealand, personal comunication, 1981.

16. McNitt, J, Klein, C, Sanyal, S.: "Interpretation of

Well Testing Results with Specific Reference to the

Calciting problem: Miravalles Geothermal Project,

Costa Rica". GeothermEx, Inc, Berkeley, Ca., June,

1981.

17. McNitt, J., Sanyal, S., Klein, C.: "Impact of Scale

Deposition on the Feasibility of Developing the

Miravalles Geothermal Field, Costa Rica".

GeothermEx, Inc, Berkeley, Ca., unpublished report.

18. Michaels, D. E.: "Deposition of CaC03 in Porous

Materials by Flashing Geothermal Fluid". Geoth.

Res. Eng. Mangmt. Prgm., LBL 10673-GREMP 9, 1980.

19. Michaels, D. E.: "C02 and Carbonate Chemistry

Applied to Geothermal Engineering" LBL 11509-GREMP

15, 1981.

20. Oddo, J., Tomson, M.: "Simplified Calculation of

CaC03 Saturation at High Temperatures and Pressures

in Brine Solutions". Journal of Petroleum

Technology, p. 1583-1590. July, 1982.

21. Ortiz, J.: "Two Phase Flow in Geothermal Wells:

Development and Uses of a Computer Code". MS

Report, Stanford University, 1983.

22. Roberts, V.: "Analysis of Scale Formation in

Geothermal Systems" EPRI, 1983.

23. Stiff, H. A., Davis, L. E.: "Method for Predicting

the Tendency of Oil Field Waters to Deposit Calcium

Carbonate". Trans. AIME, 1952.

24. Tomson, Mason : "Inhibitor Evaluation in

Geopressured Brines" Rice U. and U. of Houston

Project Review, Gas Res. Inst., HOUSton, Texas,

Feb., 1983.


1.

2.

3.

4.

5.

6.

7.

LIST OF FIGURES

Geographical location of the Miravalles geothermal

field

Geologic and topographic map showing the

exploration technique results

PGM-1 - Well design and lithology

PGM-1 - Drilling curve

PGM-1 - Temperature recovery

PGM-1 - Decline index versus time for the three

long term tests

PGM-1 - Flow rate and wellhead pressure versus time

for test 1

8A. PGM-1 - Flow rate versus time for test 2

8B. PGM-1 - Wellhead pressure versus time for test 2

9A. PGM-1 - Flow rate versus time for test 3

9B. PGM-1 - Wellhead pressure versus time for test 3

10. Equipment utilized for flow measurements

11. Surface continuous recording equipment for flow

measurements

12. Caliper logging results for wells PGM-1, PGM-2 and

PGM- 3

13. PGM-1 - Mass flow versus cummulative production for

test 2

14. PGM-1 - Mass flow versus cummulative production for

test 3

15. PGM-1 - Deliverability curve for test on 4/29/82


16.

17.

18.

19.

20.

21.

22.

23.

24.

25.

26.

27.

28.

29.

30.

31.

32.

PGM-1 - Deliverability curve for test on 5/13/82

PGM-1 - Deliverability curve for test on 5/27/82

PGM-1 - Deliverability c'urve for test on 6/2/82

PGM-1 - Deliverability curve for test on 6/24/82

PGM-1 - Deliverability curve for test on 7/8/82

PGM-1 - Deliverability curve for test on 7/30/82

PGM-1 - Deliverability curve for test on 8/12/82

PGM-1 - Deliverability curve for test on 8/26/82

PGM-1 - Deliverability curves for some typical

tests during test 3

PGM-1 - Flowrate versus time for 7.5 kg/cm2 (a)

from deliverability curves

PGM-1 - Downhole enthalpy and deliverability for

test on 4/29/82

PGM-1 - Downhole enthalpy and deliverability for

test on 5/13/82

PGM-1 - Downhole enthalpy and deliverability for

test on 5/27/82

PGM-1 - Downhole enthalpy and deliverability for

test on 6/2/82

PGM-1 - Downhole enthalpy and deliverability for

test on 6/24/82

PGM-1 - Downhole enthalpy and deliverability for

test on 7/8/82

PGM-1 - Downhole enthalpy and deliverability for

test on 7/30/82


33. PGM-1 - Downhole enthalpy and deliverability for

test on 8/12/82

34. PGM-1 - Downhole enthalpy and deliverability for

test on 8/26/82

35. PGM-1 - Mean enthalpy values (without adjustment)

versus time

36. PGM-1 - Mean enthalpy values (adjusted) versus time

37. PGM-1 - Na concentration versus time

38. PGM-1 - K concentration versus time

39. PGM-1 - Ca concentration versus time

40. PGM-1 - C1 concentration versus time

41. PGM-1 - Si02 concentration versus time

42. PGM-1 - HC03 concentration versus time

43. PGM-1 - Na/K concentration ratio versus time

44. Calcite precipitation versus wellhead pressure for

EPRI code

45. Silica precipitation versus wellhead pressure for

EPRI code

46. Calcite precipitation versus time

47. Silica precipitation versus time

48. Saturation index versus wellhead pressure for

simplified model

49. Flashing depth versus wellhead pressure for four

deliverability tests during flow test 3

50. Range of wellhead pressures and flashing depth

assumed for scale simulation

51. Wellbore conditions assumed for scale simulation


52. Flow rate versus wellhead pressure from scale

simulation

53. Real and scale simulated well performance curves

54. Area versus wellhead pressure for scale simulation

55. Equipment utilized in Cerro Prieto, Mexico for

mechanical reaming with the well flowing

56. Equipment utilized in Svartsengi, Iceland for

mechanical reaming with the well flowing

57. Combined cooling chamber and flow restriction for a

12" Grant rotating head utilized in Svartsengi

field, Iceland


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950

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t-

30:

tr

PGM-1: W VRS.PRESS.

1

FIGURE 26. PGM-1 - Downhole enthalpy and deliverability for

test on 4/29/82


70L

50F

40k

30F

PGM-1: H VS. PRESS.

PGM-1:: W VRS,PRESS.

1

FIGURE27. PGM-1 - Downhole enthalpy and deliverability for

test on 5/13/82


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FIGURE 28. .PGM-1 - Downhole enthalpy and deliverability for

test on 5/27/82


c3

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loool

950

30k I

WELLHEAD PRESSURE, KG/CM2

PGM-1: W VRS.PRESS.

i

FIGURE29. PGM-1 - Downhole enthalpy and deliverability for

test on 6/2/82


LL

J

a

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PGM-1: H VS. PRESS.

E 1050

t

loool

950 i

t

WELLHEAD PRESSURE, KG/CM2

PGM-1: W VRS.PRESS.

FIGURE^^. PGM-1 - Downhole enthalpy and deliverability for

test on 6/24/82


w

m

\

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1000

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I-

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30 L

1

0 2.5 5 7.5 10 12.5 15

WELLHEAD PRESSURE, KG/CM2

PGM-1: W VRS.PRESS.

FIGURE32. PGM-1 - Downhole enthalpy and deliverability for

test on 7/30/82


z

W

0

w

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WELLHEAD PRESSURE, KG/CM2

PGM-1: W VRS,PRESS.

I I I I 1 1 1 1

FIGURE 33. PGM-1 - Downhole enthalpy and deliverability for

test on 8/12/82


i

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FLGURE 34. PGM-1 - Downhole enthalpy and deliverability for

test on 8/26/82


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Svortsengi


LIST OF TABLES

1. Long term flow tests run at Miravalles well PGM-1

2. Chemical analysis of the particles found in the

silencer of PGM-1

3. Production data for deliverability test of 4/29/82

4. production data for deliverability test of 5/13/82

5. Production data for deliverability test of 5/27/82

6. Production data for deliverability test of 6/2/82

7. Production data for deliverability test of 6/24/82

8. Production data for deliverability test of 7/8/82

9. Production data for deliverability test of 7/30/82

10. Production data for deliverability test of 8/12/82

11. Production data for deliverability test of 8/26/82

12. Downhole enthalpy calculated for deliverability tests

14. Chemical analysis of the samples taken during test

periods 1, 2 and 3

15. Chemical analysis of the brine and condensate for

samples taken during flow test period 3

16. Selected chemical-physical data for computer analysis

for 6/02/82

17. Selected chemical-physical data for computer analysis

€or 6/2/82

18. Selected chemical-physical data for computer analysis

for 6/24/02

19. Selected chemical-physical data for computer analysis

for 6/24/02

21. Selected chemical-physical data for computer analysis

for 8/12/82


23. Selected chemical-physical data for computer analysis

for 8/12/82

24. Input data for EPRI code

25. Output data for EPRI code

26. Scaling simulation results for W=260,330 lb/h

27. Scaling simulation results for W=493,258 lb/h

28. Scaling simulation results for W=593,446 lb/h

29. Data for Rice University method


d

h

C

bl

1

rn

c

cl

0

L


0 TABLE^. Chemical analysis of the particles found in the

silencer of PGM-1

0.4%

0.-

00%

0-1%

0.W

0.2%

NbA.

1.2%

3.5


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a

iis

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4/29/82 13.20

10.50

9.40

8.70

8.00

7.50

6.90

6.20

5.50

5.40

TABLE 12

DOWNHOLE ENTHALPY CALCULATED

FOR DELIVERABILITY TESTS

80.34

so. 09

53.53

55.65

58.11

59.82

60.63

62.66

62.81

64.20

2.53

4.85

5.96

6.63

7.19

7.66

8.53

9.63

10.31

10.73

32.87

54.94

59.50

62.28

65.30

67.49

69.16

72.29

73.12

74.93

994

974

977

977

973

969

97 1

98 0

98 1

977

5/13/82 9.00 15.93 7.09 63.02 983

7.20 60.27 8.59 68.86 975

6.20

5.40

63.31

64.63

9.68

10.90

72.98

75.54

972

979

5/27/82 13.30

10.40

8.30

7.05

6.10

5.40

6/2/82 12.75

8.80

6.40

5.40

6/24/82 13.35

8.55

6.20

5.20

82.84

$1.61

56.77

61.49

66.66

63.39

39.38

54.47

60.81

63.01

35.16

53.50

58.42

BO. 05

4.32

6.23

7.23

8.62

9.91

10.94

1.76

6.70

9.26

11.47

2.54

6.53

9.15

10.64

37.16

57.84

64. 00

70.12

72.57

74.33

41. 14

61.16

70.07

74.48

37.70

60.03

67.57

70.69

1069

993

983

984

984

990

9 23

983

983

1004

97 0

979

984

990

7/8/82 14.60 17.79 3.24 21.03 1147

9.90 46.84 6.00 52.83 1005

7.65 51.96 7.73 59.69 992

6.50 $5.49 8.85 64.34 988

5.75 56.79 9.72 66.51 987

- 5.25 57.42 10.47 67.90 99 2

7130182 12.90

8.90

7.00

5.80

- 4.90

-

8/12/82 10.50

7.15

5.40

4.50

32.43

44.49

98.28

50.80

53.20

37.24

43.21

46.81

47.29

1.77

5.83

7.45

8.90

10.46

2.80

6.79

8.61

9.60

34.20

50.31

55.73

59.70

63.66

40. 04

50.00

55.42

56.89

936

993

994

997

1005

929

998

998

1008

8/26/82 .13.00 25.12 2.51 27.63 1017

8.50 38.14 5.71 43.86 1009

6.40 41.61 7.12 48.73 1003

5.40 43.66 8.21 51.87 1008

4.60 43.91 8.86 52.77 1010

4.40 44. 17 9.24 53.42 1013


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06/02/82

06/02/82

06/24/82

06/24/82

08/12/82

08/ 12/82

081 12/82

081 12/82

06/02/82

06/02/82

06/24/82

06/24/82

081 12/82

08/12/82

081 12/82

081 12/82

06/02/82

06/02/82

06/24/82

06/24/82

081 12/82

081 12/82

081 12/82

OS/ 12/82

06/02/82

06/02/82

06/24/82

06/24/82

081 12/82

08/12/82

081 12/82

081 12/82

T@LE25. Output data for EPRI code

13.70

9.74

14.29

7.14

11.44

8.09

6.34

5.44

13.70

9.74

14.29

7.14

11.44

8.09

6.34

5.44

13.70

9.74

14.29

7.14

11.44

8.0s

6.34

5.44

13.70

9.74

14.29

7.14

11.44

8.09

6.34

5.44

.3811E-03

.5486E-03

.3446E-03

.5560E-03

.3067E-03

.414lE-03

.5794E-03

.5788E-03

2 .9479S-O5

2 .3876E-03

2 . 118513-03

2 .4063E-03

2

-

2 .2845E-03

2 .4598E-03

2 .48 1 OE-03

3

3

3

-

-

-

3 .4059E-O3

3

3

3

.2845E-03

-

3 .4810E-03

.2582E-03

.4381E-03

.2159E-03

-4806E-03

.2182E-03

.3309E-03

.5024E-03

.4703E-O3

.2672E-02

.3443E-02

.1965E-02

.2868E-02

.2950E-02

.2950E-02

.2620E-02

.2785E-02

.4300E-02

.4357E-O2

.3050E-02

,378113-02

.4527E-O2

.3688E-02

.3359E-02

.3405E-02

.3350E-O2

.4122E-02

.2644E-02

,3547E-02

.3449E-02

.3448E-02

.3\ 18E-02

.3464E-02


61 e 31

34.49

15.32

13.85

13.07

12.32

12.17

12.09

11 l 95

11.87

11.80

11.73

11.69

11.68

11.68

11.67

11.66

TABLE 27

SCALING SIMULATION RESULTS FOR

9~493,258 LB/H

.7363

-5522

.3681

.3500

.3400

.3300

3280

.3270

.2350

l 3240

.3230

.3220

l 3215

-3214

.3213

,3212

3211

0.00

25.00

50.00

52.47

53.82

55.18

55.45

55.59

55.86

56.00

56.13

56.27

56.34

56.35

56.36

56.38

56.39

147.24 2125

146.75 2126

141.07 2133

137.27 2135

134.77 2135

128.77 2136

126.18 2136

125.05 2137

121.88 2137

119.11 2137

116.10 2137

111.61 2137

107.69 2137

106.32 2137

104.06 2137

100.49 2137

92.83 2137


TABLE 26

SCALING SIMULATION RESULTS FOR

Q=260,330 LB/H

AREA DIAMETER % CHOKE WHP FLASH

INCH2 FEET PSI DEPTH

(A) FT.

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

61.31 .7363

34.49 .5522

15.32 .3681

13.07 .3400

12.32 3300

10.18 .3000

4.52 .2000

4.08 .1900

0.00

25.00

50.00

53.82

55.18

59.26

72 84

74.20

TABLE 28

SCALING SIMULATION RESULTS FOR

Q=593,446 LB/H

209.13 1849

208.80 1850

208.54 1855

208.40 1859

208.30 1860

208.00 1868

200.60 2011

198.20 2060

AREA DIAMETER % CHOKE WHP FLASH

I NCH2 FEET PSI DEPTH

(A) FT.

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

61.31 .7363 0.00 107.47 2035

34.49 .5522 25.00 106.94 2038

15.32 .3681 50.00 100.56 2068

12.32 .3300 55.18 94.33 2094

11.58 .3200 56.54 75.76 2102


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APPENDIX


SAMPLE111

IBDAlA

OtT I .17E-OS* .U7IE-O2. .BOOC-OIt .12OJE-02. .41L-O* 0.01 .SZE-W* 0.0. 0.0, 0.0, 0.0. 0.0. ,.SI 0.0. 0.0.

0.01 0.0. 0.0. .WSIE-02* 0.01 0.00 0.01 .3106E-O3. .l910ft00,

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WPTIAV I 0.0, 0.0. 0.01 0.0. 0.0. 0.0. 0.0. 0.0. 0.0. 0.0. 0.0. 0.0. 0.0. 0.0. 0.01 0.0. 0.0. 0.0. 0.0. 0.0. 0.0,

0.0. 0.0, 0.0. 0.0, 0.01 0.0. 0.0. 0.01 0.0. 0.0. 0.01 0.01 0.01 0.0, 0.0. 0.0. 0.0. 0.0. 0.0. 0.0. 0.0,

0.s. 0.0. 0.0. s.01 0.0. 0.0. 0.0. 0.0. 0.0. 0.0, 0.0. 0.0. 0.0, 0.0. 0.0. 0.0. 0.0. 0.01 0.0, 0.0. 0.0,

0.0. 0.0. 0.0, 0.0. 0.0, 0.0. 0.0. 0.0. 0.0. 0.0. 0.0. 0.0. 0.0. 0.0. 0.0. 0.0. 0.0, 0.0. 0.0. 0.0. a.0.

0.0, 0.0. 0.0. 0.0. 0.0. 0.0. 0.0. 0.0. 0.0, 0.0. 0.0. 0.0. 0.0, 0.0. OIO. 0.0. 0.0, 0.0, 0;o. 0.0. 0;;;

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0.01 0.0. 0.0, 0.0, 0.0. 0.0, 0.0, 0.01 0.0, 0.0. 0.0. 0.01 0.0. 0.0, 0.0. 0.0, 0.0. 0.0, 0.0, 0.0, 0.0.

0.0. 0.0. 0.0. 0.0, 0.01 0.0. 0.0. 0.0, 0.0, 0.01 0.0. 0.0. 0.0. 0.0, 0.0. 0.0. 0.01 0.0. 0.0.

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63 FERROUS OXIDE

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1.00000002E100 I

1.00004B1)lEt00 8

1.3620054LE-07

2.S0052SOlE-O4

4.62904003E-OS

9.46070192E-03

ii nimrirr


COMPUTER CODE OUTPUT LISTING

PART I: EQUILIB - ELECTRIC PO’K’EX RESEARCH INSTITUTE (USA)


COMPUTER CODE OUTPUT LISTING

PART 11: WATCH - NATIONAL ENER3' AUTHORITY (ICELAND)


10lAL COYCEYTR~TIOY Ill LlEUtD CWASE (MOLESIK0 LIWID W20)

1

2

AL

r

.14WS53E-05

.107?211E-02

.I.

NO *

1 ALttt

2 Kt

3 YAi

4 CAtt

I nett

4 FEtt

14 I40104

14 s--

17 S04--

I0 cos--

19 CL-

20 on-

21 )I*

22 n20

2s sol---

31 AL(on>**

12 ALlOH)2t

33 AL(on)4-

34 AL(S04)t

35 AL(SO412-

41 KCL

43 KSO4-

45 NACL

44 naco3-

47 NA804-

4* CAOWt

IO CACOI

I1 CAncolt

52 CAS04

I3 noont

I4 meco3

IS IlEMCOlt

I4 ME104

so FE


SI02 535.00

M 1WO.00

K 233.00

CA 48,w

RG 0,100

co2 42.55

so4 31.20

OS 0,00

U 3100*00

F O*OO

DISShWIDS 0,00

AL 0.1000

B 47 ,oooo

FE 0,0000

NH3 o.oOO0

BEEP MATER ~PPIO

SI02 467.36

an 1648.35

K 204 6 2 8

cn 42e87

ffi 0,088

so4 28.23

U 2717,M

f 0.00

DISSaS. O B 0 0

K 0.0877

B 41e2050

FE O.oQ00

IONIC MLm :

coz 1068*78

HZS 0,OO

HZ 4,94

02 0.00

cH4 0.22

I2 81 $ 7 5

m3 0.00

NIWES C05TA RIM

0.0 0,o

0.0 0.0

0,o 0.0

0.0 0.0

0.0 o*o

0.0 0.0

0,o 0.0

0.0 0.0

0.0 0.0

o*o 0.0

0.0 0.0

0.0

0.0

0.0

0.0

0,0

0.0

0.0

0.0

0.0

0.0

0,0


m ORKUSTOFNUN

ACTIVITY COEFFICIENTS IN DCEP MTER

tlt 0,727 K W -

MI- 0.638 F-

H3SIM- 0,648 CL-

HZSIM- 0,211 Mt

HW3- 0 e 615 Kt

HC03- 0,648 w

C03- 0,191 %ti

HS- 0.658 m t

S-- 0,202 MHC03t

HS04- 0 * 658 cmt

S04-- 0,180 n6oHt

NAS04- 0.674 MUt

Ht (ACT,) 0.00

OH- 0,15

H4SIM 746,61

H3SI04- OeM

HZSIM-- 0,00

HhH3SIM 0141

H3B03 235.1

H2BO3- 0,20

H2C03 1460.15

HW3- 34.38

C03- 0.00

H2S

Hs-

0,OO

0,00

S-- 0.00

WS04 0.00

HSM- 1.09

sob- 15.43

HF

0.00

F- OX4

CL- 2404 e 71

Ndt 1576e95

Kt 197 * 45

c4tt 34.15

0 674

0.638

0,626

0.648

0.626

0.224

0,265

0.685

0.648

0.685

0 * 693

0.615

IONIC STRElTH = 0.07597 IOWIC BAWWX :

CHEMICAL GEOTHERHOMETERS LGREES C

OUARTZ 246,4

CHALCEDfflY 999,9

MK 220e9

0.648

01060

0.211

0 v 674

0.-

0,658

0,658

0.211

0,674

0,658

0,191

0.024

0.00 0.OOo

0.00 OtOo0

0.00 O B O o 0

0.00 O.Oo0

0*00 0.Ooo

o n 0 0 0.OoQ

0.00 0.000

0.00 OIOOO

0,00 o.Oo0

0.00 0.OOo

O+OO -20,654

0,00 -13,890

0.00 -8.014

0.25 -5.490

0.00 -8,709

0+00 -21.096

0.00 -221774

0,00 o*Oo0

0.00 0,OOo

0*00 o.Oo0

0,00 0.000

0.00 odc4

o m o.Oo0

M w- 99,399

TEOR, WC.

-11,526 -11,242

-2.m -2*110

2,072 99.999

-17,281 99.999

-74,109 -68,790

-37.205 -SA22

-2,121 -2.110

-3717% -36.035


m oRKUSToFNUN

LOG DISTRIBUTIW CmFICIENTS WZ =-2*49 w2s 0.00 6AS SOLUBILITY RLTIKYIffi FKTOR 1.00

WP UATER (PPI)

SI02 1500 .84 w2

I4 1766.41 H2s

II 218.31 Hz

ca 45.95 M

IG 0,094 CHI

SM 30.25 NZ

CL 2912,46 NH3

F 0*00

DISSnS, 0,OO

AL 0.0940

B 44,1563

FE 0.oOoQ

ACTIVITY UlEFFICIWTS In DEEP WTER

Ht 0 * 741 KSM-

OH- 0.655 F-

HWIM- 0,665 U-

H?SI04-- 0.233 Mt

H303- 0,632 Kt

HC03- 0,665 cat t

C03-- 0,212 Ntt

6- 0.655 M03t

S-- 0.224 ffiHC03t

HSO4- 0 t 674 CAM0

SOk- 0,200 MGWt

NASM- 0.690 IM4t

DEEP STEM P m n

74.78 m2 149)6*91

0.00 m 0.00

0,04 Hz 73.35

0,00 02 0,00

0,00 CHI 3.21

0,59 112 1214.38

0.00 )M3 0.00

0.690

0,655

0,644

0.665

0.644

0,246

0,289

0,700

0.665

0.700

0,708

ova2

CHEnItAL CMIFONENTS IW DEEP WATER (PPII WD LO6 #OLE)

FEtt

FEttt

FEOHt

FE(OH)3-

FE(OHM-

Fmtt

FE(W2t

FE(OHi4-

FES04t

FEUtt

FECLZt

FEU)-

0,00 o.oO0

0*00 0,OOo

0.00 O.OO0

0*00 0,Ooo

0,oo OIOO0

0,oo OIOOO

0*00 o.oO0

0.00 o.oO0

0,00 0,w

0.00 o.oO0

0.00 -22.015

0100 -14.977

o m -8.732

0.27 -5.468

0.01 -7,155

0.00 -22,m

0.00 -24.328

0.00 O.Oo0

0,00 o.oO0

0.00 O I O O 0

0.00 0.OOO

0.00 o*oO0

o m o.OO0


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CJMcuIwY

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