Reservoir Characteristics(with some introductory reservoir engineering)

“Geothermal Systems for Geoscientists”

Rick AllisSeptember 15 2010

Special thanks to Paul Bixley, Contact Energy Ltd, N.Z. for some of the well log data

Conceptual Models

What are the relationships between lithology, structure, temperature and permeability (and fluid flow)?

Remember that geothermal power is concerned with heat extraction from the subsurface – the fluid moving through the pore space (and fracture network) is the mechanism

for extracting that heat.

Conceptual model of high temperature system from Cumming (2009)

Conceptual model of moderate temperature system from Cumming (2009)

Conceptual Reservoir Model for volcano-hosted system

Fig. 2. Schematic cross section through the earth’s crust showing the key elements of a typical commercial volcanic-hosted geothermal system. The exploration process typically includes the sampling and analysis of waters and gases from hot springs and fumaroles, geophysical measurement of subsurface rock resistivities using the time-domain electromagnetic ( 1 km depth of investigation) and magnetotellurics (>5 km depth of investigation) techniques, and both shallow and deep drilling. The goal of shallow drilling is to identify and map the conductive heat flow anomaly overlying the geothermal system. The goal of deep drilling is to penetrate the geothermal reservoir, if it exists, and produced fluids.

Williamson et al, 1989

Thermal models from Blackwell et al., 2007 for Dixie Valley Power Plant area (central NV)

GNS Science consultancy Report 2010/138

Note that where the main hot spring and geyser activity was, it is cold at depth (this field has been affected by pressure decline at nearby Wairakei field since 1960)

Models for vapor zones

Ingebritsen and Sorey (1983)

• Slide

Vertically extensive vapor-dominated systems are rare, but several exist in Java, Indonesia.

Where do we start? – let’s look at the well data

Tauhara Field, N.Z., Contact Energy Ltd

Temperature and Pressure Logs• Probably the most important data to have

– Temperature and permeability information is essential for understanding the reservoir (is there a thermal resource, and can you get it out!)

• Logs can be “static” (i.e. shut-in); or flowing – under injection or production

• The best permeability (i.e. best “feed zone”) in the well dominates the flow regime (shut-in or flowing) – gives indication of formation pressure• May see inter-zonal flow as isothermal sections on temperature logs (sometimes difficult to decide whether flow is up or down)

Remember this slide from the “Harnessing the Heat Lecture”? It show the different density gradients for cold and hot water, and steam (plus the effect of increased loading on the pores with increasing depth)

Want would be the effect of a high permeability feed zone at say 500 m depth, and at 35 bars?

The observed pressure profile depends on the fluid state in the bore bore, which is equilibrating with the reservoir at 500 m depth (and 35 bar).

Note the pressure pivot, and the difference in water “level” in the well.

DownHole Combined Pressure/Temperature

KA41 PT 20/12/2005 04:50 Well Temperature KA41 PT 20/12/2005 04:50 Well PressureKA41 PT 27/12/2005 12:57 Well Temperature KA41 PT 27/12/2005 12:57 Well Pressure

Temperature [°C]350300250200150100500

Pressure [bara]1751501251007550250

Verti

cal D

epth

[m]

1,800

1,700

1,600

1,500

1,400

1,300

1,200

1,100

1,000

900

800

700

600

500

400

300

200

100

under injection

T P

Heating 1 week

P T

• Major loss zone (and rapid heat up) at 1410 m depth

• Minor loss zone at 1200 m depth, and possibly minor loss zone at well bottom

• Pivot in pressure curves as liquid in wellbore heats up and becomes less dense – formation pressure at 1410 m depth is 121 bar gauge

• Temperature here is at least 300ºC(Possibly conductive gradient down to about 1000 m depth)• Note under injection the cool water level is at about 200 m depth (water was being poured in); however heated water column probably has +ve WHP – implying reservoir outflows as hot springs • Note also under injection, the pressure in the wellbore exceeds likely formation pressure below pivot

• What we see in the logs may only represent the formation conditions at a few points!

• However we can still infer significant characteristics with careful detective work!

Logging tool being prepared for “run”

Wells can equilibrate with a steam zone which overlies a liquid reservoir – giving formation pressures at two depths - one in deeper liquid, and one in overlying steam zone

How representative of the reservoir are the two profiles?

28-3 Roosevelt Field, UT, Pacificorp

What do you see here?

DownHole Combined Pressure/Temperature

MK13 PT 23/03/2004 10:51 Well Temperature MK13 PT 23/03/2004 10:51 Well PressureMK13 PT 24/03/2004 05:48 Well Temperature MK13 PT 24/03/2004 05:48 Well PressureMK13 PT 27/03/2004 09:25 Well Temperature MK13 PT 27/03/2004 09:25 Well PressureMK13 PT 30/03/2004 12:17 Well Temperature MK13 PT 30/03/2004 12:17 Well PressureMK13 PT 6/04/2004 12:36 Well Temperature MK13 PT 6/04/2004 12:36 Well Pressure

Temperature [°C]350300250200150100500

Pressure [bara]1751501251007550250

Verti

cal D

epth

[m]

1,400

1,300

1,200

1,100

1,000

900

800

700

600

500

400

300

200

100

0

Logs run while well heating up over two weeks

DownHole Combined Pressure/Temperature

MK13 PT 23/03/2004 10:51 Well Temperature MK13 PT 23/03/2004 10:51 Well PressureMK13 PT 24/03/2004 05:48 Well Temperature MK13 PT 24/03/2004 05:48 Well PressureMK13 PT 27/03/2004 09:25 Well Temperature MK13 PT 27/03/2004 09:25 Well PressureMK13 PT 30/03/2004 12:17 Well Temperature MK13 PT 30/03/2004 12:17 Well PressureMK13 PT 6/04/2004 12:36 Well Temperature MK13 PT 6/04/2004 12:36 Well Pressure

Temperature [°C]350300250200150100500

Pressure [bara]1751501251007550250

Verti

cal D

epth

[m]

1,400

1,300

1,200

1,100

1,000

900

800

700

600

500

400

300

200

100

0

Logs run while well heating up over two weeks

• Pivot (formation pressure) at about 1300 m depth (110 bar g)

• wellhead is accumulating gas as it heats up

• pressure profile is sufficient to generate hot springs/outflow at surface

• maximum temperature is around 305ºC at 1200 m depth - possibly the main feed zone took in a lot of cold injection water and is taking a long time to recover….(?)

• there may be a conductive thermal gradient down to at least 500 m depth at this site

DownHole Combined Pressure/Temperature

PK05 PT 19/04/2005 12:12 Well Temperature PK05 PT 19/04/2005 12:12 Well PressurePK05 PT 19/04/2005 13:47 Well Temperature PK05 PT 19/04/2005 13:47 Well PressurePK05 PT 19/04/2005 14:34 Well Temperature PK05 PT 19/04/2005 14:34 Well PressurePK05 PT 19/04/2005 17:45 Well Temperature PK05 PT 19/04/2005 17:45 Well PressurePK05 PT 24/05/2005 13:30 Well Temperature PK05 PT 24/05/2005 13:30 Well Pressure

Temperature [°C]350300250200150100500

Pressure [bara]1751501251007550250

Verti

cal D

epth

[m]

2,400

2,300

2,200

2,100

2,000

1,900

1,800

1,700

1,600

1,500

1,400

1,300

1,200

1,100

1,000

900

800

700

600

500

400

300

200

100

0

What does a low permeability well look like?

• High wellhead pressure under injection

• No clear loss zone under injection (and temperature gradually cooled over 5 hours)

• Slow to heat up on recovery

Various injection logs over 5 hours

Injection logs over 5 hours

Logs 5 weeks after injection runs

Completion Tests (injectivity tests)• Carried out after drilling ceased and usually after

final casing or liners are run• Purpose is the identify the permeability

characteristics of the well• Note: should already have information from

cuttings geology, drilling loss zones/kicks, drill bit drops (breaks)

• Typically inject water at several flow rates, and simultaneously do T/P log plus spinner log, also caliper log, maybe cement bond log

• Injectivity is simply the change in flow rate for a given change in wellhead (or downhole) pressure

• Units are tonnes/hour per bar• In these units (t/h/bar),

– Injectivity < 5 ………….tight well– Injectivity 10 – 20 …….small producer– Injectivity > 50 ……….excellent!

• Injectivity tests are a useful guide for productivity (Grant, 2009)

• Injectivity with cold water tends to be higher than productivity (why?)

• Prolonged injection of cold water can cause injectivity can increase with time, and is sometimes used as a form of stimulation

Examples of Injectivity from Roosevelt Field, Utah: 7 – 30 t/h/bar (note significant transient effects at low flow rates)

Examples of Injectivities of 8 – 10 t/h/bar from Mak-Ban field, Philippines (example from Grant et al. 1982; 1 MPa = 10 bar)

Production Testing – dry steam: flow rates can be measured using range of flow meters designed for single phase fluid in pipes (e.g. pressure drop across orifice plate (temperature and non-condensible gas content important)

Figure from Grant et al. (1982)

Production Testing - Two-Phase Fluid

For portable equipment• Calorimeter Max 30 t/h• Separator Max 200 t/h• Lip pressure & Weir Max 600 t/h• Lip Pressure (Vertical Discharge; know enthaply)• Tracer Dilution tested in Philippines

Production Testing - Lip Pressure & Weir Method(James 1966)

Lip Pressure and Weir Method

• Can solve for “h” from steam fraction calculation, known separation pressure, and water mass flow (James, 1966; summary in Grant et al., 1982)

0.184 phG0.96

1.102 =×

AM G =

0.184 pA 3600

hM0.96

1.102

=××

×)kgkJ(enthalpy Fluidh

)(cm pipe discharge of area sectional CrossA )hr(tonne flowrate Total M

sec)cm(tonne areaunit per FlowrateG absolute)(bar pressure lip p

2

2

Testing well output

Wells have a maximum rate of discharge at near-zero wellhead pressure, and a maximum discharge pressure with low flow and imminent collapse of the 2-phase column

ABC

A

BC

Base case

Reduced reservoir pressure

Increased reservoir pressure, or rise in temperature, gas content

D: effect of scaling in wellbore

E: effect of lowered reservoir permeability

F: 2-phase flow at same pressure as A

From Grant et al., 1982

Example of discharge curve from a hot well in Tauhara Field, N.Z. (GNS Science Consultancy Report 2010/138

What would be the thermal output at 10 bar?

TH12

TH6Output test for a well with steam and liquid feedzones (TH6, Tauhara Field, N.Z.; from GNS Science Consultancy Report 2010/138)

The crucial information we need about the reservoir is the thermal regime (spatial and amplitude) and an understanding of what is controlling the permeability (how much fluid we can out of our wells). We get this from the T/P logs during heat up, and under injection and discharging

In contrast to the petroleum wells and ground water wells, a wide variety of well logs are not often run; part of the problem is the well has to be below 150 ºC for most electronic tools! That can be an issue in the deeper (more interesting) sections of geothermal wells!

Usually some sort of cement bond log and caliper log are run while the rig is still in place to check that the casing is in place as intended, and the casing, liner (and if there is open hole – this is unusual) have the required diameter. With time, scaling (mineral deposition) can occur, restricting the discharge, and corrosion may also occur. These initial logs are important as a baseline for well integrity.

Casing Condition

• HHCCHot Hole Casing CaliperMagnetic InspectionMeasures amount of

metal = wall thicknessMeasure IDMeasure internal defects

Conceptual Model – Awibenkok, Indonesia(volcano-hosted)

-1500

-1000

-500

0

500

1000

1500

2000

0 50 100 150 200 250 300 350

Pressure(bar g); Temperature (oC)

Elev

atio

n (m

asl)

Reservoir Pressure

ReservoirTemperature

Cl Spring

northeast wells

west wells

Salak volcanosummit

AWIBENGKOK GEOTHERMAL FIELD

hydrostatic from field elevation

hydrostatic from adjacent valley floor

Allis, 1999

A well in this field had many logs run in an open hole section as a test of the value of logs

In future lectures we will look at the changes with time in reservoirs due to development, and what we monitor to observe these changes to optimize energy production