1

1. INTRODUCTION

This report is a partial contribution from Iceland to the

International Energy Agency Geothermal Implementing

Agreement (IEA-GIA), Annexes VII and XI and the

Lower Cost Drilling Annex of the International Partner-

ship for Geothermal Technology (IPGT).

After successful development of the Nesjavellir Field in

the Hengill Geothermal Area (first plant commissioned

in 1990, generating 120 MWe of electricity and 300

MWth of hot water), Reykjavik Energy decided to ex-

plore other prospects in the area for new plants. In the

period 2001-2011 the company drilled 55 exploration

and production wells as well as 17 reinjection wells in

the Hengill Area, and 5 make-up wells in the Nesjavellir

Field. The Hellisheidi Geothermal Plant, about 20 km

east of Reykjavík, was commissioned in four stages

2006-2011. It generates now 303 MWe of electricity in

two units and 133 MWth of hot water for district heating.

This intensive drilling activity in the same geothermal

area provided a unique source of data to obtain statistical

estimates of the cost and effectiveness of geothermal

drilling. The number of working days to complete each

of four depth sections of the well (surface, anchor, pro-

duction casings and the slotted liner) was analyzed and

the results were grouped according to which well design

was used and technology applied. Cost calculations in

this study are based on assumed market prices for servic-

es and material, as the real cost was not made available.

The drilling was done by Iceland Drilling Ltd. after int-

ernational tendering. The majority of the wells were dr-

illed with modern drill rigs, up to four at the same time.

The rigs are all-hydraulic with a top-drive and the large

ones with automatic pipe handling. The time breakdown

in this study was worked out from the geological daily

reports prepared by Iceland GeoSurvey as the daily rig

reports are confidential.

Former efforts to analyze this data were undertaken by

Sveinbjornssonand Thorhallsson 1,2,3. This paper re-

ports selected topics from these references, with emphas-

is on the frequency of problems which led to excessive

additional cost. The study compares workdays in drilling

holes with two different casing diameter programs, for

vertical and directional drilling. Completion tests at the

end of drilling provide an Injectivity Index which serves

as a preliminary estimate of future flow rates from the

well. Such tests are of importance for deciding whether

to drill deeper, drill a sidetrack or to apply well stimula-

tion before moving the drilling rig off the well. To ob-

tain reliable predictions of steam mass flow on the basis

of the Injectivity Index one must, however, consider re-

servoir conditions and enthalpy of the expected inflow

ARMA 13-386

Drilling performance and productivity of geothermal wells - Case history from Hengill Geothermal Area in Iceland

Sveinbjornsson, B.M.

Iceland GeoSurvey, Reykjavik, Iceland

Thorhallsson, S.

Iceland GeoSurvey, Reykjavik, Iceland

Copyright 2013 ARMA, American Rock Mechanics Association

This paper was prepared for presentation at the 47th US Rock Mechanics / Geomechanics Symposium held in San Francisco, CA, USA, 23-26

June 2013.

This paper was selected for presentation at the symposium by an ARMA Technical Program Committee based on a technical and critical review of the paper by a minimum of two technical reviewers. The material, as presented, does not necessarily reflect any position of ARMA, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of ARMA is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 200 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgement of where and by whom the paper was presented.

ABSTRACT: Drilling performance of 77 production and reinjection wells in the Hengill Geothermal Area in Iceland is analyzed.

The study compares workdays, and time spent on seven different drilling activities, in drilling holes with two casing diameter pro-

grams, both vertical and directional. The Monte Carlo method was applied to obtain a statistical estimate of the number of work-

days and the cost of a 2235 m deep directional reference hole. On average this hole needed 45 workdays with a standard deviation

of 7.2 days. The cost was inferred from time and usage data as the actual costs were not available for the study. The average cost

for a large diameter reference well is 4.3 million USD or about 2000 USD/m. Drilling problems due to loss of circulation or coll-

apsing geological formations led to higher drilling costs for 24 wells but the majority of holes were drilled according to the origin-

al schedule. The risk of drilling such holes in terms of cost and output is not as high as often alledged. To predict steam mass flow

on the basis of the Injectivity Index, determined at the end of drilling, one must consider reservoir conditions and enthalpy of the

expected inflow into wells. About 80% of the drilled wells are productive. The average generating capacity is ~5.9 MWe per drill-

ed well. Injection of waste water from the power plant resulted in thousands of earthquakes, of magnitude up to Ml 4.

2

into wells. About 80% of the drilled production and

make-up wells turned out to be productive. The power

output of the large diameter wells is 30-40% higher than

that of the regular diameter wells.

Injection of waste water from the Hellisheidi power

plant led to an intense swarm of induced earthquakes

which gradually declined in frequency and magnitude.

While the results obtained in the Hengill field may not

apply in fields with different geology and reservoir char-

acteristics, the approach in this paper could lead to valu-

able comparisons.

2. DRILLING PERFORMANCE

2.1 Drilling in the Hengill Area A recent description of the conceptual model of the

Hengill geothermal system was given by Franzson et al.

4. The drill fields are shown in Fig. 1.

Fig. 1. Prospective fields in Hengill Geothermal Area. Most of

the wells drilled in the years 2001-2011 were in the Hellis-

heidi, Grauhnukar and Hverahlid Fields. Figure from Iceland

GeoSurvey.

Fig. 2 shows the location and trajectories of wells and

the formation temperature in the drill fields.

Two types of casing designs for high temperature wells

were used. The wells of both programs were either drill-

ed vertical or directional. The most common type is a

directional well with a “large diameter” casing program.

The pre-drilling (Section 0) is done by a small rig with a

26" bit down to 90 m for a 22½" surface casing, follow-

ed by Section 1 drilled by a larger rig with a 21" bit to

300 m for the 18⅝" anchor casing. Inclined drilling

starts with a kick-off point (KOP) in Section 2, where

the inclination is gradually built up by 2.5-3.0° per 30 m.

The section is drilled with a 17½" bit to 800 m for 13⅜"

production casing. The open hole in Section 3 is drilled

with a 12¼" bit to a depth of 1800 to maximum of 3300

m for 9⅝" slotted production liner. The other design is

narrower, each casing one size smaller, and called the

“regular diameter” casing program. The sections are the

same but the diameters 18⅝" of the surface casing, 13⅜"

anchor casing, 9⅝" production casing, and 7" slotted

production liner. Fig. 3 shows examples of the design of

a vertical well of regular diameter and a directional well

of large diameter.

Fig. 2. Formation temperature in the Hellisheidi, Grauhnukar

and Hverahlid Fields of the Hengill Area at 1000 m below sea

level, about 1400 m depth. Blue dots and lines indicate well-

heads and trajectories of directional wells. A red star on the

trajectory indicates where the well reaches the depth of the

map. Figure from Bessason et al. 5 .

Fig. 3. Examples of the design of a vertical well of regular dia-

meter and a directional large diameter well. On left, the four

depth intervals for the reference well, Sections 0, 1, 2 and 3.

The same section numbers are used in Tables 1 to 4. Figure

from Iceland GeoSurvey.

3

The pre-drilling to about 90 m was performed with air

hammer and foam, or with tricone insert bits, using mud

and water as circulation fluids. Rotary drilling techniq-

ues with tricone insert bits were applied in Section 1, but

in Section 2 a mud motor was used to rotate the bit and a

Measurement While Drilling (MWD) tool inserted in the

drill string to monitor direction (azimuth) and inclination

(degrees) of the well. In Section 3 until total depth no

mud was used but drilling was carried out with only wat-

er as long as there were no circulation losses. After loss-

es were encountered the circulation was in most wells

switched over to aerated water by compressed air for

pressure balance drilling.

Seven drill rigs were used to carry out the drilling. Two

small rigs with a hook-load capacity of 50 tonnes were

often used for the pre-drilling to 90 m depth. An inter-

mediate rig (100 t) was sometimes used for the sections

to 300 m to meet the tight schedule and fully utilize the

rig fleet. The four large rigs (180, 200, 300 t) were used

in all sections, and always in the deepest one (Fig. 4).

Fig. 4. A drilling rig with 200 tonnes hook-load capacity on

site at Hellisheidi field. Photo from Iceland Drilling Ltd.

2.2. Time Analysis of Drilling Data To compare the drilling time for different wells, the re-

spective numbers of workdays were normalized for a

reference well of that design and the average depth of

the group which was 2235 m. The frequency distribution

of workdays for each section was found to be asymmetr-

ic with the most frequent value lower than the average.

An example of this distribution is presented in Fig. 5 for

the workdays in drilling Section 3 from 800-2235 m in

46 large diameter directional wells. The data is best fitt-

ed by a Beta-PERT distribution, defined by the lowest,

most likely and the highest value observed.

Table 1 shows the lowest, most likely and highest values

of normalized workdays in drilling the four sections of

directional large diameter wells. Average and standard

deviation are calculated for the respective Beta-PERT

distribution. The number of wells analyzed for each sect-

ion varies as fewer reports were available from Section 0

of pre-drilling and Section 1 drilling for the anchor cas-

ing. The most complete set of geological reports is avail-

able from drilling Section 2 for the production casing

and Section 3 drilling of the open hole.

Fig. 5. Frequency distribution of normalized workdays in drill-

ing Section 3 from 800-2235 m in 46 large diameter direct-

ionally drilled wells.

Table 1. Normalized workdays for directional, large diameter

reference wells.

Section Drilled Number Lowest Most likely Highest Average(m) (days) (s) (%)

0 0-90 38 3 4 14 5.5 1.8 331 90-300 44 4 8.5 29 11.2 4.2 372 300-800 46 6 9 20 10.3 2.3 233 800-2,235 46 8 16 36 18.0 4.7 26

Total 2,235 45.0 6.9

Wells Workdays Beta-PERTSt. deviation

To obtain an estimate of the variance in total cost Monte

Carlo simulations with 50,000 trials were carried out

using the Beta-PERT probability distributions in Table 1

for the number of workdays. Fig. 6 shows the distribut-

ion of the resulting total of workdays in drilling of large

diameter wells.

Fig. 6. Monte Carlo simulation of the distribution of total

workdays of a large diameter directional reference well to

2235 m. The mean is 45.0 days and the standard deviation

7.23 days. With 95% confidence the workdays lie between

32.1 and 60.1 days as indicated by arrows.

The workdays were also analysed for each of the four

sections of drilling and the time used for seven different

activities such as actual drilling, running and cementing

casing, delays due to drilling problems, logging, install-

ation of wellhead, repairs of equipment and other reas-

ons for delays. The results are shown in Table 2.

4

Table 2. Percentages of total workdays used in different activ-

ities of drilling a directional, large diameter reference well.

WorkdaysSection Drilled Number Average Drilling Casing Problems Logging Completion Repairs Other

(m) (n) (d) (%) (%) (%) (%) (%) (%) (%)0 0-90 38 5.5 47.0 28.1 9.5 0.0 11.0 1.7 2.71 90-300 44 11.2 36.6 26.3 10.0 9.9 12.5 2.9 1.72 300-800 46 10.3 46.6 21.7 5.1 11.2 11.0 3.9 0.63 800-2,235 46 18.0 54.4 5.8 11.1 15.8 7.5 4.8 0.6

Total 45.0

Wells Percentage in different activities

Table 3 compares the number of workdays for large dia-

meter directional and vertical wells, and Table 4 shows

the same comparison for “regular” diameter wells. The

number of wells varies according to the number of each

type drilled and the availability of reports. The average

and the standard deviation are calculated assuming a

Beta-PERT distribution for the workdays. The total

workdays for the large diameter directional wells are

45.0 days compared to 45.8 days for much fewer vertical

wells.

Table 3. Workdays for large diameter directional and vertical

wells. The first two sections of all wells to 300 m are drilled

vertically. The rest of the well, Sections 2 and 3, are then eith-

er drilled directionally or vertically.

Section Depth Diameter Number Days St. dev. Number Days St. dev. Number Days St. dev.

(m) (") of wells (d) (s) of wells (d) (s) of wells (d) (s)0 0-90 26 38 5.5 1.81 90-300 21 44 11.2 4.22 300-800 17½ 51 10.3 2.3 46 10.3 2.3 5 9.8 0.83 800-2,235 12¼ 53 18.0 4.7 46 18.0 4.7 7 19.3 3.7

Total/Average 45.0 6.9 45.0 6.9 45.8 5.9

Large diameter program All wells Directional wells Vertical wells

The directional regular diameter wells take 43.5 days on

average but fewer vertical wells 48.3 days. Considering

the numbers in each group and the respective standard

deviations the difference in total workdays is not signifi-

cant. It is of interest to note that for directional wells the

average for 17 narrower program wells is 43.5 days

compared to 45.0 days for 46 wells of the large diameter

program.

Table 4. Workdays for regular diameter directional and verti-

cal wells.

Section Depth Diameter Number Days St. dev. Number Days St. dev. Number Days St. dev.

(m) (") of wells (d) (s) of wells (d) (s) of wells (d) (s)0 0-90 21 25 5.8 2.21 90-300 17½ 25 8.3 2.02 300-800 12¼ 23 11.5 2.8 17 10.7 2.0 6 12.2 2.83 800-2,235 8½ 22 21.3 6.3 17 18.7 3.0 5 22.0 6.3

Total/Average 47.0 7.5 43.5 4.7 48.3 7.5

Regular diameter program All wells Directional wells Vertical wells

2.3. Drilling Cost and Problems Although most wells were drilled close to the original

time schedule, some wells encountered difficulties re-

sulting in workdays exceeding considerably the average

for the respective activity. The drilling reports were exa-

mined to find the causes for the excess workdays. Most

common were problems due to loss of circulation or

collapsing geological formations where the rig got stuck.

The time analysis identified such incidences in 24 wells

or 31% of the 77 wells drilled. The additional cost was

though low in most cases. Problems due to geological

formations were the primary cause of problems in 18 of

the 24 wells. They led to other problems such as diffi-

culties in running the casing in three wells and excessive

cement loss into the formation. In five wells the rig got

stuck and had to cut the drill string by explosives, losing

the bottom hole assembly, collars and part of the drill

pipes in the well. This occurred twice in one well. Four

wells were sidetracked due to a stuck drill string and two

because of a wrong direction. Two wells were abandon-

ed because of a collapse and a stuck drill string. Repairs

on the top drive were necessary during drilling four

wells, sometimes due to excessive strain in attempts to

free a stuck string. In two wells the section of initial

drilling had to be divided into two steps due to over-

pressure in shallow boiling aquifers.

Caves due to the collapse of walls often presented severe

problems for continued drilling and demanded large

quantities of cement to fill. Such caves remain as poorly

cemented sections and increase the risk of casing dam-

age when the well is subjected to large variations in

temperature. An example is given in Figs. 7 and 8.

Fig. 7. A view from side on the upper end of the ruptured pro-

duction casing. Photo from Iceland GeoSurvey.

Fig. 8. A view from side on the lower end of the ruptured pro-

duction casing. Note the coupling thread grooves. In the back-

ground fractured rock filled with cement. Photo from Iceland

GeoSurvey.

5

There a 50 cm break was found at 310 m depth in the

production casing of well HE-53, 4 m below the end of

the anchor casing.

The additional cost due to drilling problems was estimat-

ed on the basis of workdays that were required to solve

the problem beyond the average number of workdays re-

quired in the respective section. Also taken into account

was the cost of cement, bentonite-mud and other suppli-

es in excess of what is accounted for in a reference well.

Sections that were abandoned by sidetracking were

counted as additional cost in workdays and material us-

ed. Thirdly the cost of lost equipment and drill string in

the hole that could not be recovered, was included as lost

in hole charge. Fig. 9 shows the cost above the average,

for the 24 problem wells.

Fig. 9. Additional cost due to drilling problems in individual

wells, total 24 wells.

The additional cost was compared to the estimated cost

of drilling the reference well of the large diameter pro-

gram. That cost was calculated on the basis of the numb-

er of workdays required for each section of the drilling,

using a weighted average of the day rates for different

activities. The material costs on the other hand depend

on commodity prices of steel, cement, fuel oil etc. They

are relatively predictable because the quantities needed

are known. A breakdown of cost for different sections is

shown in Table 5.

Table 5. Breakdown of cost for a large diameter directional

reference well to 2235 m.

To obtain an estimate of the variance in total cost Monte

Carlo simulations with 50,000 trials were carried out

using probability distributions for the number of work-

days, the unit costs of material, and day rates for the

drilling rigs. The results are in Fig. 10. Considering the

standard deviation s of $450,000 for the reference well,

18 of the wells have an additional cost less than 3 s

To obtain a view in terms of the s the additional cost

was divided by the s and the frequency calculated as

Fig. 10. Monte Carlo simulation of the total cost of a large

diameter directional reference well to 2235 m. The mean is

$4,317,588 and the standard deviation $451,229. The cost lies

with 95% confidence within the limits $3,517,000 and

$5,262,000 as indicated by arrows.

percentage of the total wells drilled. Fig. 11 shows the

result. For 77 wells drilled the additional cost was larger

than one s in 18 wells or about 23%. It exceeded 2 s in

10 wells or 13% and 3 s in 6 wells or nearly 8% of the

total. This distribution can be of aid in estimating additi-

onal risk due to problems on top of the risk included in

the statistical distribution of the reference well.

Fig. 11. Percentage of the total of 77 drilled wells with additi-

onal cost due to drilling problems larger than a multiple of the

standard deviation s of the reference well.

3. PRODUCTIVITY OF WELLS

3.1. Injectivity

Grant 6 addressed the relationship between injectivity

and productivity of wells and optimization of decision

criteria whether to accept a well, sidetrack it or to dis-

miss the drilling rig and undertake a full well test. The

Injectivity Index (II), (kg/s)/bar, is determined at the end

of drilling by logging the downhole pressure response

near the dominating feeder to different rates of pumping

water onto the well (e.g. 20, 40 and 60 kg/s), each step

lasting approximately 3 hours. It serves as the first indi-

cator of the well productivity. Injectivity normally incr-

eases with continued injection due to thermal stimulat-

ion. To compare wells one must therefore use values ob-

tained in completion tests before any extended injection

period. Fig. 12 shows the relative frequency distribution

of the Injectivity Index in 73 production and injection

wells in the Hengill Area.

6

Fig. 12. Relative frequency of Injectivity Index for 73 product-

ion and injection wells in the Hengill Area.

The distribution is asymmetric with a longer tail to high-

er values. The logarithm of the Injectivity Index is, how-

ever, normally distributed as demonstrated in Fig. 13,

showing fit of the data with the cumulative probability

of a lognormal distribution with a mean of log10(II)=

0.78 and a standard deviation of log10(II) = 0.35.

Fig. 13. Cumulative probability of the Injectivity Index for 73

production and injection wells in the Hengill Area. The proba-

bility is calculated using a lognormal distribution for the loga-

rithm of the Injectivity Index.

The cumulative probability denotes the probability that

the Injectivity Index (II) is less or equal to the corre-

sponding value. The mean (50%) corresponds to II = 6.0

(kg/s)/bar which is the most likely value for the Injectiv-

ity Index while the average equals 8.7 (kg/s)/bar.

3.2. Productivity Extensive data on the flow test of wells is available from

Sigfusson et al. 7. Figs. 14 and 15 show the relative

frequency distribution of the total mass flow rate (kg/s)

and the steam mass flow rate for 43 production wells in

the Hellisheidi Field of the Hengill Area. The distribut-

ion of both the total flow and the steam flow is lognorm-

al as that of the Injectivity Index. Fig. 16 shows a fit of

the total mass flow data with the cumulative probability

of a lognormal distribution with a mean of log10 (Qtotal) =

1.50 and a standard deviation of log10 (Qtotal) = 0.33.

Fig. 14. Relative frequency of total mass flow rate (kg/s) at 8

bar-g separation pressure for 43 production wells in the Hellis-

heidi Field.

Fig. 15. Relative frequency of steam mass flow at 8 bar-g

separation pressure for 43 production wells in the Hellisheidi

Field.

The mean corresponds to Qtotal = 31.6 kg/s which is the

most likely value for the obtained total mass flow in a

productive well while the average equals 39.2 kg/s.

Fig. 16. Cumulative probability of total mass flow at 8 bar-g

separation pressure for 43 production wells in the Hellisheidi

Field. The probability is calculated using a lognormal distri-

bution for the logarithm of the total mass flow.

Fig. 17 shows the fit for the steam mass flow data with a

mean of log10 (Qsteam) = 1.07 and a standard deviation of

log10 (Qsteam) = 0.40. The mean corresponds to Qsteam =

11.7 kg/s which is the most likely value for the obtained

steam mass flow in a productive well although the aver-

age equals 16.4 kg/s.

7

Fig. 17. Cumulative probability of steam mass flow at 8 bar-g

separation pressure for 43 wells in the Hellisheidi Field. The

probability is calculated using a lognormal distribution for the

logarithm of the steam mass flow.

The steam ratio x = Qsteam/Qtotal is the steam fraction, re-

ferred to as quality, at 8 bar-g separation pressure which

for the wells ranges from 0.08 to 0.99 and has an aver-

age of 0.44. For a water inflow at a temperature of 220-

340°C the steam ratio at 8 bar-g should be in the range

of 0.09-0.42. This indicates that for most of the wells the

inflow is a two phase mixture of steam and water where

the steam dominates in volume.

3.3. Injectivity, Mass Flow and Steam Yield In search of a relation between the Injectivity Index and

the total mass flow a log/log-graph of total mass flow of

wells at 8 bar-g separation pressure was drawn against

the Injectivity Index (Fig. 18).

Fig. 18. Total mass flow at 8 bar-g separation pressure in 43

wells drawn against the Injectivity Index using bilogarithmic

scales. The data points and shading indicate groups of antici-

pated reservoir temperatures of the dominating feeders of indi-

vidual wells in the range of 220-250°C, 250-280°C, 280-

300°C and 300-320°C.

The range of mass flow lies between 10-100 kg/s and the

Injectivity Index between 2-35 (kg/s)/bar. Fig. 18 indi-

cates a relation of the kind suggested by Grant and Bix-

ley 8 but the data points are scattered due to different

reservoir temperatures of the dominating feeders and

boiling inflow into wells. Approximate curves are drawn

through the corresponding data points. For a known

Injectivity Index and reservoir temperature this graph

can be used to estimate the future mass flow. To obtain

reliable predictions of steam yield on the basis of the In-

jectivity Index one must, however, consider reservoir

conditions and enthalpy of the expected inflow into

wells. In view of the excess steam in inflow the relation

between the Injectivity Index and the total mass flow

will only give a minimum estimate for the expected st-

eam yield. Most of the wells do yield more than that

minimum as evidenced by the mean steam ratio of 0.44.

3.4. Power Output of Wells The overall economics of a geothermal power project is

strongly influenced by the power output per well, or how

much can be reinjected, which is also considered in eval-

uating the drilling effectiveness. Table 6 shows the aver-

age power output per drilled geothermal production well

and a productive well in the Hellisheidi Field of the

Hengill Area.

Table 6. Average megawatts of electricity (MWe) that can be

generated per drilled well and per productive well in the Hell-

isheidi Field.

Diameter Number of drilled Number of drilled

production wells productive wells

Large 37 29 6.4 8.2Regular 17 14 4.9 5.9Total/Average 54 43 5.9 7.5

Power per drilled

well (MWe)

Power per productive

well (MWe)

To generate 1 MWe the turbine alone requires a steam

flow rate of 1.9 kg/s but considering parasitic consumpt-

ion a conservative rate of 2.2 kg/s is used in this article.

The average power output per drilled well amounts to

5.9 MWe but 7.5 MWe per productive well. The large

diameter wells yield 30-40% more steam. To evaluate

the advantage of drilling large diameter wells instead of

regular diameter one must also consider the cost. The

material cost of a large diameter well is about 30% high-

er than that of a regular diameter well, but as shown in

Chapter 2.2 the time cost for a large diameter well was

not significantly higher than that of a regular diameter.

Considering the ratio of time cost versus material cost

the total cost of a large diameter well in the Hengill

Field is thus only 10% higher than that of a regular dia-

meter well.

4. INDUCED SEISMICITY

The Hengill Area is at the intersection of the South Ice-

landic Seismic Zone (SISZ) with the Western Rift Zone

(WRZ). The WRZ is characterized by northeasterly er-

uptive fissures and normal faults. The SISZ has an und-

erlying sinistral EW transform fault but the surface

breaks in dextral NS and conjugated sinistral ENE strike

slip faults. Both systems have been active in the Hengill

Area as shown on Fig. 19.

The Hengill Area is noted for swarms of earthquake act-

ivity with events reaching magnitude Ml 6 every 30

years. Induced seismicity occurred during drilling of

8

Fig. 19. Blue lines are eruptive fissures and faults in the Heng-

ill Area. Green lines indicate seismic faults. Red dots are sur-

face manifestations of geothermal activity. Figure adapted

from Arnason and Magnusson, 9.

some wells in the Hellisheidi Field. This was clearly

demonstrated while drilling the reinjection wells HN-12

and HN-17 at Husmuli near the western rim of the field

(Fig. 20). The following description of induced seismic-

ity at Husmuli is based on an extensive report by Bessa-

son et al. 5.

Fig. 20. Location of reinjection wells (gray lines) at Husmuli

on the western rim of the Hellisheidi Field. The red stars indi-

cate distribution of earthquakes with magnitude Ml >1.5 that

occurred while drilling HN-17. Orange lines are eruptive fiss-

ures. Red lines with ticks are normal faults. Figure from

Bessason et al. 5.

Fig. 21 shows how loss of circulation in drilling HN-17

led to intense swarms of earthquakes.

Fig. 21. Earthquake swarms while drilling the reinjection well

HN-17. Red bars indicate occurrence and magnitude of earth-

quakes. The blue line shows accumulated number of earth-

quakes. Figure from Bessason et al. 5.

Geothermal waste water and condensed steam from the

first unit of the Hellisheidi Plant was reinjected into

wells at Grauhnukar some 4 km SSW of Husmuli. No

earthquake activity occurred during drilling of these

wells and the injection of 200-300 l/s induced no seism-

icity either.

Reinjection from the second unit of the plant into four

wells at Husmuli started in early September 2011. Since

September 23 the reinjection has been 400-600 l/s of 80-

100°C hot water. The wellhead pressure is about 7 bar-g

and the pressure at the receiving formation is about 28

bars higher than before the injection. This overpressure

is not sufficient to create new but may open existing

fractures. The acceptance of wells improves with lower

temperature of the injected water. This may indicate that

thermal contraction aids in opening the existing fract-

ures.

On September 8 a swarm of earthquakes started near

Husmuli. In view of the earthquakes that occurred dur-

ing drilling the wells this was not unexpected but the

number of earthquakes and their magnitude was larger

than anticipated. From September 2011 to May 2012,

4600 earthquakes of magnitude M l > -0.4 were recorded.

About 150 earthquakes exceeded Ml 2.0, about 40 Ml

2.5, and 8 were in the range Ml 3.0-4.0. The two largest

events of Ml 4.0 occurred on October 15. They may have

been associated with a temporary break of several hours

in the reinjection, followed by a sudden increase in pore

pressure as the reinjection began again. This break was

due to loss of electric power in bad weather. Sudden

changes in pore pressure are known to trigger induced

seismicity (Majer10). Fig. 22 shows the rate of rein-

jection and the associated earthquake activity.

9

Fig. 22. (a) Rate of reinjection of waste water into wells at

Husmuli (red curve) and temperature of the water (blue curve)

from early September 2011 to end of April 2012. (b) Recorded

earthquakes: Red bars indicate occurrence and magnitude of

earthquakes. The blue line shows accumulated number of

earthquakes. Figure from Bessason et al. 5.

Fig. 23 shows relative location of the earthquakes from

the beginning of September 2011 to the end of April

2012. During those months the activity spread 2-3 km

northwest delineating parallel northerly striking fracture

zones. The dominating focal mechanism in the earth-

quakes is strike slip with some component of normal

slip. It is noteworthy that the earthquakes do not corre-

late with normal faults in Husmuli but delineate norther-

ly fracture zones similar to those found in larger earthqu-

akes of the SISZ. The reinjection of 500 l/s has been

continued without sudden interruptions since April 2012

and the induced seismicity is still declining, no events

larger than Ml 1.5. The areal distribution of the induced

earthquakes and the decreasing intensity indicate that the

tectonic regime is approaching a new equilibrium with

the injected water.

5. CONCLUSIONS

No significant difference was found in the time required

to drill holes of the wider 13⅜" production casing or the

regular narrower casing of 9⅝" diameter. No difference

either was found in the time used to drill vertical or in-

clined directional wells. The average power output per

drilled well amounts to 5.9 MWe but 7.5 MWe per pro-

ductive well. The wider wells cost 10% more than the

narrower wells but yield 30-40% more steam.

The results of this analysis of drilling performance clear-

ly indicate that the perceived high risk in geothermal

drilling is less than often alledged. The standard deviat-

ion of the total cost of a well is about 10% of the average

cost. Only 6 wells, or 8% of the total 77 wells drilled,

had costs exceeding 3 standard deviations. The risk lies

mainly in the nature of the geological formation, prob-

lems due to loss of circulation or collapsing walls where

the rig gets stuck.

Fig. 23. Relative location of earthquakes associated with rein-

jection at Husmuli. (Upper figure) Earthquakes in September

(dark blue) and October 2011 (blue-green). The stars show

location of the two largest earthquakes of Ml 4 that occurred

on October 15. (Lower figure) Earthquakes from September

2011 to April 2012. The colors for each month are different.

The diamonds are GPS-stations. Figure from Bessason et al.

5.

10

Comparison of injectivity and productivity of wells indi-

cates that to obtain reliable predictions of steam mass

flow on the basis of the Injectivity Index one must also

consider reservoir conditions and enthalpy of the expect-

ed inflow into wells. In a reservoir where a boiling mix-

ture of steam and water enters the well the injectivity test

can only predict the total mass flow and the correspond-

ing minimum steam mass flow.

Reinjection of geothermal waste water and condensed

steam led to an intense swarm of induced seismicity cul-

minating after 6 weeks in two events of Ml 4. Decreasing

frequency and magnitude over 18 months indicate that

the tectonic regime is approaching a new equilibrium

with the injected water.

ACKNOWLEDGEMENTS

We thank Reykjavik Energy for permission to use the drilling

data from the Hengill Area. Reykjavik Energy and National

Energy Authority (Orkustofnun) gave financial support to

undertake this work. The authors would like to thank the Inter-

national Energy Agency/Geothermal Implementing Agree-

ment and the US Department of Energy for their travel support

to present this paper which we trust encourages international

cooperation on topics being pursued by Annex VII, Advanced

Geothermal Drilling and Logging Technologies. Brynja Jons-

dottir, Iceland GeoSurvey and Gunnar Gunnarsson, Reykjavik

Energy, are thanked for technical drawings. Einar Jon As-

bjornsson, Iceland GeoSurvey and an anonymous reviewer are

thanked for useful comments.

REFERENCES

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2012.

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NOMENCLATURE

Bar-g gauge reading of pressure in bar

Beta Greek letter, type of distribution

II Injectivity Index (kg/s)/bar

ISOR Iceland GeoSurvey

KOP Kick Off Point

m meter

MW megawatt

MWD Measurement While Drilling

PERT Program Evaluation Review Technique

Q mass flow (kg/s)

s standard deviation of a distribution

Std. dev. standard deviation of a distribution

t hook lift capacity in tonnes

x steam ratio of total mass flow

Qsteam steam mass flow (kg/s) at 8 bar-g separation

pressure

Qtotal total mass flow (kg/s) at 8 bar-g separation

pressure

Greek letter

s standard deviation of a distribution

Subscripts

e electric

th thermal

total steam and water (kg/s)

Superscripts

" width in inches (25.4 mm)

° degrees

Conversion factor

1 bar 105 Pa