PROCEEDINGS, Thirty-Seventh Workshop on Geothermal Reservoir Engineering

Stanford University, Stanford, California, January 30 - February 1, 2012

SGP-TR-194

RESPONSE OF OLKARIA EAST FIELD RESERVOIR TO PRODUCTION

James M. Mariaria

Kenya Electricity Generating Company

P.O. Box 785-20117

Naivasha, Rift Valley, 20117, Kenya

E-mail: jmariaria@kengen.co.ke

ABSTRACT

Kenya has been exploiting the geothermal energy

resource for the last 27 years. Geophysical and

geological surveys were conducted between L.

Bogoria and Olkaria and the latter identified as the

most potential prospective area. Exploration of the

resource commenced in 1956 that show the drilling

of two exploratory wells, X1 and X2. The Olkaria

field was segmented into seven sectors to facilitate

easier utilization. Extensive drilling operations

started in Olkaria East Field that led to the

establishment of three units in June 1981, November

1982 and March 1984, each unit producing 15MWe.

The Greater Olkaria Field is being exploited and

currently atleast 200 MWe is being produced from

the field and plans are underway to increase the

output as evidenced by the drilling operations that are

on-going currently. Olkaria East Field has been

sustaining the 45MWe and drilling operations are

currently being carried out to establish an additional

140 MWe power plant by 2013 in the same field. Hot

and cold reinjection has also been introduced to

enhance reservoir recharge. It is in view of this that

this paper seeks to explore the response of Olkaria

East Field Reservoir to production and the effects of

reinjection system.

INTRODUCTION

Kenya was the first African country to explore and

develop the geothermal resource. The geothermal

resources in Kenya are mainly located in the Great Rift

Valley region. Geological and Geophysical surveys

were conducted in the 1950s between L. Bogoria and

Olkaria and the latter was predicted to have massive

geothermal resource.

The surveys were carried out by the United Nations

Development Programme (UNDP) in collaboration

with the Government of Kenya and East African

Power and Lighting Company Ltd. It is estimated that

the Kenya Rift has a potential of greater than 7000

MWe of Geothermal Power. The greater Olkaria

region was sub-divided into seven segments majorly

for easier development of the geothermal field. Two

exploratory wells, X1 and X2, were drilled in Olkaria

(1956).The wells were not impressive and this

necessitated scientific review of data to atleast

determine the exact location of the resource.

Production drilling commenced in the 1970s that led

to the establishment of three geothermal power units,

each comprising of 15Mwe, between 1981 and 1985.

The plant has an installed capacity of 45MWe.

OLKARIA GEOTHERMAL FIELD

The Olkaria Geothermal Field is located in the

Kenya Rift valley, Naivasha, which is about 120 km

from Nairobi, covering an area of about 204 km2

(figure 1). The geothermal field has been sub-

divided into seven segments namely Olkaria East,

Olkaria North-East, Olkaria North-West, Olkaria

South-West, Olkaria Central and Olkaria Domes

(figure 2). Four power plants are currently installed

and producing electricity in the field, Olkaria I with

45 MWe capacity, Olkaria II with 105 MWe

capacity, Olkaria III with 48 MWe capacity and

Oserian with 4 MWe. The first two are operated by

KenGen while the third and fourth are operated by

Independent Power Producers namely, Orpower4

Inc. (Ormat) and Oserian Development Company

respectively.

Figure 1: Map showing Kenya Geothermal sites

OLKARIA EAST PRODUCTION FIELD

Currently 45MWe is being generated by Olkaria I

geothermal power station. The first Geothermal

power unit at Olkaria I was a 15 MWe generating unit

commissioned in June 1981 and the second 15 MWe

commissioned in November 1982. The third unit was

commissioned in March 1985 raising the total

installed capacity of the plant to 45 MWe.

Figure 2: Greater Olkaria Sectors

The turbines are 4-stage single flow running with an

inlet steam pressure of 5 bars absolute at a

saturation temperature of 152°C and a steam

consumption of 10 tonnes per hour for each

megawatt hour produced. The plant has had an

average availability and load factor of 98 per cent

since commissioning. The power generated is

connected to the national grid via a 132 kV

transmission line. So far atleast 55 wells have been

drilled in the Olkaria East Field. The layout of the

field and location of wells is shown in Figure 3. Out

of The already drilled wells, 25 wells of them are

currently connected to Olkaria I power plant and

supplying a total of 782 t/h of steam and 263 t/h of

brine.

FIGURE 4: Location of wells drilled in OEF

Another 6 wells have been retired due to decline in

their steam and pressure production levels. Two of

the retired wells, OW-3 and OW-6, are currently

used for hot and cold injection on trial basis.

Additional wells have been drilled while others are

currently being drilled and others have been sited to

be drilled thereafter in this field for the 140 MWe

Olkaria I units 4&5 additional units.

FIGURE 5: Steam output trends from Olkaria

East Field from 1981 to 2010

These wells will be connected during construction

of the Olkaria I units 4&5 power plant. The wells

connected to Olkaria I power plant have performed

well since the plant was commissioned in 1981.

After commissioning of Olkaria I unit III in 1985,

the field experienced some output decline. To

mitigate, make up wells were drilled and connected

to the steam gathering system. The makeup wells

restored the plant’s rated output. The steam output

trend is as shown in Figure 5 above. Some decline

in production occurred in the first ten years of

exploitation due to the depletion of the shallow

steam zone but after connection of make-up wells

in 1996, there have been no more declines

experienced. Only eight make-up wells were drilled

and total steam available has been in excess since

connection of the make-up wells.

OLKARIA EAST RESERVOIR RESPONSE

Twenty three (23) wells had been drilled and

connected to the steam supply system when

Olkaria I 45Mwe had been installed in March

1985. The wells had been drilled to depths ranging

from 900 m to 1685 m except OW-19 that had

been drilled to 2484 m. As fluid extraction

continued during production, some of the wells

that had been drilled to depths between 900 m to

1200 m declined in output and had to be isolated

from the steam supply system. In mitigating these

declining wells productivity, new make-up wells

were drilled to restore the rated plant’s generating

capacity. Four make-up wells were connected in

1995 (OW-27, 28, 29 and 30), two in 1996 (OW-

31 and 33) and another two (OW-32 and 34) in

2001. OW-5 was also deepened from 900 m to

2200 m in 1998. Total steam available has been in

excess since then (Table 1).

STEAM SUPPLY STATUS AT OLKARIA I

Olkaria I power plant uses an estimated 450 t/h of

steam at an inlet pressure of 5 bar a. The wells

connected to Olkaria I power plant have a total

steam output capacity of 782 t/h.

Table 1: Summary Status of Steam Supply

Design inlet pressure (bar g) 4.2

Specific steam consumption (t/hr/Mwe) 10

Installed capacity (Mwe) 45

Steam demand (t/hr) 450

Steamfield output capacity (t/hr) 782

Excess steam output (t/hr) 332

Excess steam output supplied to Olkaria I(t/hr) 32

Excess steam at Olkaria I (t/hr) 300

Part of the steam from wells drilled in the Olkaria

East Field is supplied to Olkaria II Power Plant.

Currently, there is an excess of about 300 t/hr of

steam from Olkaria I field. A summary of steam

supply status is shown in Table 1 above.

REINJECTION

Reinjection is when water (hot or cold) is pumped

deep underground within the geothermal system

itself (infield reinjection) or outside the system

(outfield reinjection). Geothermal reinjection

systems are being employed in the geothermal

fields as a method for waste-water disposal for

environmental reasons. Recent developments have

shown that it is also being used to counteract

pressure draw-down (water-level decline) due to

long term exploitation of the resource. The natural

rate of recharge (replenishment by rainfall) would

not be commensurate to the rate of extraction

resulting in pressure drawdown. Thus reinjection

has been considered as an artificial means of water

recharge to the reservoir, to aid in extracting more

of the thermal energy stored in the reservoir

system and to reduce land subsidence caused by

over extraction of geothermal fluids.

Some operational dangers and problems are

associated with reinjection. These include the

possible cooling of production wells, often

because of short-circuiting or cold-front

breakthrough, and scaling in surface equipment

and injection wells because of the precipitation of

chemicals in the water.

REINJECTION IN OLKARIA EAST FIELD

Both hot and cold reinjection systems have been

experimented in the field with OW-03 being used

as a hot and cold reinjection well while OW-06 is

a cold reinjection well, utilizing the cooling towers

blowdown from the Olkaria I power plant. OW-12

used to reinject cold water from L. Naivasha into

the reservoir but it has since been stopped.

EFFECTS OF REINJECTION IN OEF

Well OW-02

This well was monitored in September 2010 and

was producing 18.9 t/h steam, 12 t/h brine and

1952kJ/Kg enthalpy.

1980 1985 1990 1995 2000 2005 2010

YEAR

0

10

20

30

40

50

FL

OW

(T

/HR

)

0

500

1000

1500

2000

2500

EN

TH

AL

PY

(K

J/K

G)

Graph 1Steam

Water/brine

Mass

Enthalpy

Figure 6: Output from OW-2

In August 2009 the well gave an average output of

18.8 t/h of steam, 13.6 t/h of brine and enthalpy of

1871 kJ/kg. The annual average steam outputs in

2004, 2005 and 2006 were 17.1 t/h, 17.5 t/h and

19.1 t/h respectively. A general trend of decrease

in steam and brine was observed from the early

1980s to 1995. From 1998 to 2005, steam, brine

and enthalpy have remained relatively constant

(Figure 6).This was attributed to the effects of hot

re-injection in well OW-03. Over the last 2 years,

brine has had increasing trend resulting to a decline

in enthalpy. This may be attributed to the cold

reinjection currently taking place in OW-06

(Wanyonyi 2011). However, cold reinjection effects

from OW-06 have been felt of late as it has been

noted from an increasing trend of brine that has

resulted to a decline in enthalpy.

Well OW-19

From 1980s to 1996 this well experienced an

increase in brine output and decline in steam output

resulting in decrease in enthalpy.

1980 1985 1990 1995 2000 2005 2010

0

10

20

30

40

50

60

70

FL

OW

(T

/HR

)

0

500

1000

1500

2000

2500

3000

EN

TH

AL

PY

(K

J/K

G)OW-19

Steam

Water/Brine

Mass

Enthalpy

Fig 7: Output from OW-19

However, from 1996, there is an increase in both

steam and brine output resulting to an almost

constant enthalpy (Figure 7). This is attributed to

the effects of cold injection conducted in well OW-

12 from 1995 to 1996. From 2006 to present, there

was a steady increase of steam and brine output.

WELL PRODUCTION MONITORING

Bi-annual output monitoring is done in wells that

are delivering steam to Olkaria I power plant for

periods running from January-June and July-

December. The main objective of the steam field

monitoring is to help observe important changes

taking place in the reservoir. These include

changes in reservoir temperature and pressure,

enthalpy and mass output changes as well as well’s

cyclic behaviors. These changes could result from

reservoir boiling, over-exploitation, entry of cold

water into the reservoir that can cause cooling,

wellbore scaling or direct re-injection returns in the

reservoir. Careful monitoring techniques help to

map out thermodynamic and chemical changes

before they cause adverse effects in the reservoir.

ENTHALPY CHANGES

The enthalpy contour plots shows that the center of

the field around wells OW-10, OW-18, OW-20 and

OW-24 &28, 31 and 33 has the highest enthalpy.

The southern and eastern part of the field around

wells OW-15, OW-16, OW-19, OW-22 and OW-26

seem to be receiving some cold inflow and this

depicts their low enthalpies. The enthalpy contour

plots for 2001 (FIG 7.3) is similar to the present

contour plot but the enthalpy values are higher now

than they were five years ago. This shows that most

part of the field has experienced pressure drawdown

resulting in boiling. FIG 7.4 shows that from 2001

to present, pressure drawdown has been extending

from the center to other parts of the field especially

to the west and north.

Figure 8.1: Enthalpy contour plot

for the year 2010

Figure 8.2: Enthalpy contour plot

for the year 2009

199200 199400 199600 199800 200000 200200 200400 200600 200800 201000 201200

9900800

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OW-5

OW-8

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OW-11OW-13

OW-15

OW-16

OW-18

OW-19

OW-20

OW-21

OW-22

OW-23

OW-24

OW-25

OW-26

OW-27

OW-28

OW-29 OW-30

OW-31

OW-32

OW-33

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EASTINGS (M)

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)

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OW-11OW-13

OW-15

OW-16

OW-18

OW-19

OW-20

OW-21

OW-22

OW-23

OW-24

OW-25

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OW-27

OW-28

OW-29 OW-30

OW-31

OW-32

OW-33

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EASTINGS (M)

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NO

RT

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(M

)

The year 2001 is a good reference point since all

wells currently producing were already

connected to the steam gathering system by

2001. A contour plot of enthalpy changes from

2001 to 2010 (Figure 8.3) shows that enthalpy

has increased more around the center of the field,

around OW-10, and the southeastern part of the

field around OW-30. From 2001, enthalpy

decline is observed around wells OW-15, OW-23

probably due to incursion of cooler fluids at

depth.

Figure 8.3: Enthalpy changes from

2001 to 2010

Figure 8.4: Enthalpy contour plot

For the year 2001

TEMPERATURE AND PRESSURE

CONTOURS

TEMPERATURE CONTOURS

Figure 9.1: Temperature distribution

at 0 m. a. s. l.

Figure 9.2: Temperature distribution

at 500 m. a. s. l.

OW-2

OW-3

OW-4 OW-5

OW-6

OW-7

OW-8

OW-10

OW-11

OW-12

OW-13

OW-14

OW-15

OW-16

OW-17

OW-18

OW-19

OW-20

OW-21

OW-22

OW-23

OW-24

OW-25

OW-26

OW-27

OW-28

OW-29

OW-30

OW-31

OW-32

OW-33

OW-34

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210215220225230235240245250255260265270275280285290295300305310315320325330335

OW-5

OW-11

OW-19

OW-21

OW-23

OW-25

OW-26

OW-27

OW-28 OW-29OW-30

OW-32

OW-33

OW-34

OW-35

OW-35A

OW-36

OW-36A

OW-37A

OW-38A

OW-41

OW-42OW-44

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185190195200205210215220225230235240245250255260265270275280285290295300305310

OW-5

OW-10

OW-11

OW-19

OW-21

OW-23

OW-25

OW-26

OW-27

OW-28 OW-29

OW-30OW-32

OW-33OW-34

OW-35

OW-35A

OW-36 OW-36A

OW-37A

OW-38A

OW-41

OW-42OW-44

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N O R T H I N G S ( M )

Figure 9.3: Temperature distribution at

-500 m.a.s.l.

PRESSURE CONTOURS

Figure 10.1: Pressure distribution at

500 m. a. s. l.

DOWNHOLE MEASUREMENTS

Well OW-08

The water rest level has remained at 850m from 1980s

to present. The well has had a progressive cooling

since 1985. Over the last 20 years, maximum cooling

has taken place at 1300m. The well has cooled by

about 5°C within the water column since 2001. The

pressure decline over the last 20 years has been

minimum, i.e., a maximum of 9 bars within the liquid

phase and cooling of about 18°C at about 1300 m

depth.

Figure 10.2: Pressure distribution at

0 m. a. s. l

Figure 10.3: Pressure distribution at

-500 m. a. s. l.

The well has experienced minimum cooling at

1100m depths and at the well’s bottom.

0 50 100 150 200 250 300 350

Pressure (Bara) and Temperature (°C)

1600

1400

1200

1000

800

600

400

200

0

Dep

th (

m)

Press 19.02.85

Press 17.10.00

Pres 10.05.06

Temp 19.2.85

Temp 17.10.02

Temp 10.05.06

Temp 03.05.07

Press 03.05.07

Temp 19.08.08

Press 19.08.08

Figure11: Downhole profiles in OW-08

199500 200000 200500 201000

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185190195200205210215220225230235240245250255260265270275280285290295300305310

OW-5

OW-10

OW-11

OW-19

OW-21

OW-23

OW-25

OW-26

OW-27

OW-28 OW-29

OW-30OW-32

OW-33OW-34

OW-35

OW-35A

OW-36 OW-36A

OW-37A

OW-38A

OW-41

OW-42OW-44

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4446485052545658606264666870727476788082848688909294

OW-5

OW-10

OW-11

OW-19

OW-21

OW-23

OW-25

OW-26

OW-27

OW-28 OW-29

OW-30

OW-32

OW-33 OW-34

OW-35

OW-35A

OW-36

OW-36A

OW-37A

OW-38A

OW-41

OW-42OW-44

199500 200000 200500 201000

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50

55

60

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80

85

90

95

100

105

110

115

120

125

130

OW-5

OW-11

OW-19

OW-21

OW-23

OW-25

OW-26

OW-27

OW-28 OW-29

OW-30OW-32

OW-33 OW-34

OW-35OW-35A

OW-36

OW-36A

OW-37A

OW-38A

OW-41

OW-42OW-44

199500 200000 200500 201000

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9900500

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65

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85

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100

105

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115

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135

140

145

150

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170

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OW-5

OW-19

OW-34

OW-35

OW-35A OW-36A

OW-37A

OW-38

OW-38A

OW-41

OW-42

OW-44

38B

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Over the last five years, the wellbore pressure has

increased by 1-2 bars within the water column

showing that the reservoir pressures are recovering.

This well has been shut-in for a long time and

therefore values obtained here are quite reliable.

ON-GOING DEVELOPMENTS IN OEF

WELLHEAD GENERATION

The wellhead technology has been embraced by the

organization and a pilot project is under construction.

Green Energy Generation Ltd is undertaking the

project. OW-37A was earmarked for the construction

of a 5MWe wellhead plant. Plans are also there to

increase the capacity of wellhead generation to

75MWe in the Greater Olkaria Field.

Figure 12: Part of the wellhead equipment

at OW-37A

DRILLING OPERATIONS

Drilling activities in Olkaria I and the Greater Olkaria

are currently being undertaken as evidenced by the

number of Drilling Equipments on site. Currently,

five rigs are on site, four hired and three owned by

the Kenya Electricity Generating Company

(KenGen). Among the three rigs that are owned by

KenGen, two of them (2000Hp) are newly acquired.

The decision to purchase the two rigs is the

company’s commitment to rapidly avail enough

steam for power generation and showing its

commitment to the production of clean, reliable,

environmental friendly and cost- effective energy in

the national grid. Olkaria I Unit 4&5 will be installed

to utilize the steam that has and yet to be realized as

drilling operations are on-going. The contract has

already been awarded for 140Mwe Olkaria I

expansion and 140Mwe Olkaria IV development with

Sinclair Knight Merz (SKM) being the overall

consultant. The two projects will be carried out

concurrently and they are expected to be

accomplished at the end of 2013.

FIELD OPTIMIZATION STUDY

For continued assessment of the resource, KenGen

has contracted a consortium composed of Mannvit

hf, ÍSOR, Vatnaskil ehf and Verkís hf from Iceland,

which has been awarded the project entitled

“Provision of Consultancy Services for Geothermal

Resource Optimization Study of the Greater Olkaria

Geothermal Fields”.

Figure13: Mast Raising of KGN-Rig I on OW-11

Pad in readiness to drill OW-11A

DISCUSSIONS

The EPF wells have been showing considerable

supply of steam to the power station over the last

two decades. The production performance has

exceeded the earlier predicted performance of the

field. This might be attributed to the introduction of

in-field cold and hot re-injection technology and

deeper drilling technology.

CONCLUSION

Olkaria East Field has proven to be highly

productive and more geothermal power can be

obtained from it. Deep drilling in the field has

shown considerable improvement in the productivity

of the wells drilled. OW-5 deepening showed

tremendous results in the wells steam output.

Currently, deep vertical and directional drilling to

depths of 3000m has been embraced in the Greater

Olkaria region. In Olkaria I field, OW-38B proved

to be the biggest producer in Kenya and the whole

of Africa.

REFERENCES

Bore, C.K., (2011): Steam Availability and

Development plans at Olkaria, Kenya. Proceedings,

Kenya Geothermal Conference Nairobi, November

21-22, 2011

Ofwona, C. O., (2010): Resource assessment of

Olkaria I geothermal field, Kenya. Proceedings,

World Geothermal Congress, Bali, Indonesia (2010)

Ouma, Peter (2011): Proposal to carry out additional

drilling to increase generation capacity at Olkaria

Geothermal within the KenGen geothermal license

area by 560MWe KenGen Internal Reports 2011

Wanyonyi, Eliud (2011): Report on Assessment

of Reservoir and Steam Status of Olkaria East

Production Field, March 2011 (KenGen Internal

Reports)