Geothermal drilling and completion

Compared to the oil/gas industry, geothermal drilling activity is minuscule. Worldwide installed geothermal generating capacity is approximately 8,000 MW (Table 1),[1] and for typical production from a geothermal well of 6 to 10 MWe, along with injection wells equal to one-third the number of producers, this represents a total of only 1,000 to 1,600 active wells. This number is somewhat misleading because many more wells have been drilled than are currently active. There are exploratory wells that were needed to identify and evaluate the geothermal reservoirs, many former production or injection wells have been plugged and abandoned, and much workover drilling for active power plants is required by the corrosive and solids-laden brines in many geothermal reservoirs. In spite of all this, the market is still so small that few drilling contractors or service companies can be sustained solely by their geothermal drilling business.

  • Table 1—Worldwide Installed Geothermal Electrical Generating Capacity in 2002 in Megawatts Electric(MWe)

Contents

  • 1 Nature of geothermal formations
  • 2 Slimhole drilling
  • 3 Geothermal drilling technology
    • 3.1 Bits
    • 3.2 Tubulars
    • 3.3 Drilling fluids
    • 3.4 Well control
    • 3.5 Directional drilling
    • 3.6 Cementing
  • 4 Geothermal well completions
  • 5 Case histories of two geothermal wells
    • 5.1 Steam well
    • 5.2 Brine well
  • 6 Additional references
  • 7 References
  • 8 Noteworthy papers in OnePetro
  • 9 External links
  • 10 See Also
  • 11 Category

Nature of geothermal formations

Typical rock types in geothermal reservoirs include:

  • Granite
  • Granodiorite
  • Quartzite
  • Greywacke
  • Basalt
  • Volcanic tuff

Compared to the sedimentary formations of most oil/gas reservoirs, geothermal formations are, by definition:

  • Hot (production intervals from 160°C to above 300°C)
  • Often hard (240+ MPa compressive strength), abrasive (quartz content above 50%)
  • Highly fractured (fracture apertures of centimeters)
  • Underpressured
  • Often contain corrosive fluids
  • Some formation fluids have very high solids content[

total dissolved solids (TDS) in some Imperial Valley brines is above 250,000 ppm ]

These conditions mean that drilling is usually difficult, with problems that include:

  • Rate of penetration and bit life are typically low[2]
  • Corrosion is often a problem[3]
  • Lost circulation is frequent and severe
  • These problems are often compounded by high temperature

Lost circulation and reservoir damage deserve special mention. Lost circulation is often massive; complete loss of returns at pumping rates of hundreds of barrels per hour is common. Geothermal wells have been abandoned because of the inability to drill through a loss zone,[4] and many more have needed an unplanned string of casing to seal off a problem interval. Lost circulation treatment is complicated by the requirement that the treatment not damage the producing formation, and this distinction is often difficult. Geothermal wells have been drilled into “live” production zones; that is, the hole is producing steam or hot brine during drilling. This is conventional practice in The Geysers, where the production zone is air-drilled and the produced fluid is dry steam; this is often described as “drilling a controlled blowout.” Drilling with brine inflow is much riskier, so an alternative is to allow moderate losses and to lose drilling mud into the producing fractures, with a later backflow from the production interval to clean up the formation. Productivity of most production wells up to 340 mm casing is up to 0.6 million kg/hr, so the formation has very little skin damage initially. If wells are to be drilled after brine production has begun (often a clean-out workover), this requires mufflers, rotating heads, mud coolers, and high-temperature wellhead/blowout preventer (BOP) equipment. It also means making connections in a hot hole and sometimes running liners in a live well. Although some of these operations are similar in principle to underbalanced drilling (UBD), the temperature and flow rates mean that the problems are much different from oil/gas UBD and must be well understood to avoid damage or injury from loss of well control.

Lost circulation material (LCM) is sometimes effective,[5] but often fails because losses are through fractures with apertures of several centimeters so that the LCM particles are not large enough to bridge the loss zone. If zones with fractures must be sealed, cement is usually the treatment of choice but is hard to place accurately. It is much more important to repair loss zones where casing will later be set than in production intervals. Cotton-seed hulls are used to provide temporary LCM in Imperial Valley production zones because they eventually disintegrate and produce little residue in the wellbore flowback for cleanup. Cement plugs are not used because extensive lost circulation in the reservoir indicates good fractures, which are productive. Time and materials for lost circulation treatment can represent 15% of well cost, and the underpressured formation aggravates differential sticking, so these can be major impacts on drilling cost.

Depth and temperature of geothermal resources vary considerably. Several power plants, (e.g., Steamboat Hills, Nevada and Mammoth Lakes, California) operate on lower-temperature fluid (below 200°C) produced from depths of approximately 330 m, but wells in The Geysers produce dry steam (above 240°C) and are typically 2,500 to 3,000 m deep. In the most extreme cases, an exploratory well with a bottomhole temperature of 500°C at approximately 3,350 m has been completed in Japan,[6] and experimental holes into molten rock (above 980°C) have been drilled in both Hawaii and Iceland.

Slimhole drilling

Typical geothermal exploration comprises drilling a large-diameter, production-size well and, if it shows the presence of fluid and high temperature, producing steam or brine from it while measuring the fluid temperature, and, ideally, downhole pressure. These flow tests, which usually last for days to weeks, directly evaluate the energy or enthalpy output of the well and indicate whether the reservoir pressure is drawndown significantly over the course of the test.

This method has major disadvantages:

  • It is expensive (U.S. $1 to 3 million per well)
  • There is significant environmental impact from roads, large drill sites, and fluid-handling requirements

In addition, if the operator hopes to turn an exploration well into a production well, it may be located at the fringe of the resource where it is not convenient for eventual construction of a power plant. If data from a smaller hole is adequate to evaluate the reservoir, then slimhole exploration is typically much less expensive.

Drilling slimholes is cheaper than production-size wells because:

  • The rigs, casing and cementing, crews, locations, and drilling fluid requirements are all smaller
  • Site preparation and road construction in remote areas is significantly reduced
  • It is not necessary to repair lost-circulation zones before drilling ahead.[7]

Core rigs, most often used by the minerals industry to explore for ore bodies, use diamond bits which cut a thin-kerf hole 51 to 150 mm in diameter with corresponding core diameters of 25 to 100 mm. Cores are wireline-retrieved, so the drill string is not tripped except to change bits. Weight on bit or rate of penetration is usually controlled by a hydraulic feed cylinder. Because the cuttings produced by the diamond bits are very fine and make up a smaller fraction of the hole volume than in rotaryrig coring, minerals-type core drilling can continue without drilling fluid returns, in contrast to conventional rotary rigs producing cuttings large enough to stick the drillstring, if they are not circulated out of the hole.

There are tradeoffs between rotary and core drilling, but small hole sizes have generally favored core rigs. These rigs may not be cost-effective in oil/gas exploration because, in many sedimentary formations, rotary drilling has much faster penetration and can drill those intervals more cheaply. However, the advantage of being able to drill through lost circulation zones in geothermal formations can offset faster penetration.

After drilling an exploratory geothermal slimhole, it is essential to evaluate the reservoir’s potential for commercially viable production. The two most important reservoir qualities are its temperature and its resistance to fluid flow. Because permeability is a local measurement and most geothermal production is through fractures, flow resistance is quantified as permeability integrated over some wellbore length. This is called transmissivity and has units of m3. Well testing is discussed in Geothermal reservoir engineering.

Reservoir temperature can usually be determined easily, either through logs after drilling and completion, or even from logs or maximum-reading thermometers during drilling (most geothermal drilling permits require periodic downhole temperature measurements as a criterion for casing programs.) Because of the low circulation rates used for slimhole core drilling (typically 0.75–1.25 L/s), the formation temperature recovers from the cooling effect of the drilling fluids much more quickly than in conventional rotary drilling.

Direct cost comparison of slimhole and rotary drilling in the same reservoir is provided by two wells drilled in Oregon in the 1990s. The rotary hole, “slim” by oilfield standards, was drilled approximately 3 km away from and before the slimhole. The slimhole was rotary drilled for approximately 950 m and then core-drilled to total depth (TD). Costs for the wells are summarized in Table 2.

  • Table 2—Summary of Rotary Drilling vs. Slimhole Costs

Several points are evident in the following comparison:

  • Even though charges by the drilling contractor were considerably greater for the slimhole than for the rotary hole, lower ancillary costs for the slimhole made the total project much cheaper. Rate of penetration for core drilling is typically less than that for rotary rigs, so part of the greater rig cost was caused by the longer time required for the slimhole, and the remainder is because of the rig day-rates.
  • The drilling-fluids expense was slightly greater for the slimhole, but it was inflated by the complete loss of circulation in the lower part of the hole.
  • Even though more than half the total footage was rotary drilled, the smaller bits used in the rotary section and the less expensive core bits in the cored section greatly reduced the cost of bits and tools. There were no stabilizers or drill collars in the cored section.
  • Smaller sizes of the rig, pad, and sump reduced rig mobilization and site construction costs.
  • A mud-logging service company and contract drilling supervision were only used for the rotary section of the hole.
  • Smaller casing sizes, with correspondingly smaller cement volumes, were less expensive for the slimhole.

Geothermal drilling technology

The drilling conditions described above have led to the following practices, which are reasonably uniform, in the geothermal drilling industry.

Bits

Because of the hard, fractured formations, roller-cone bits with tungsten-carbide inserts are almost universally used for geothermal drilling. The abrasive rocks mean that bit life is usually low (50 to 100 m), but many bits are also pulled because of bearing failures caused by rough drilling and high temperature. Polycrystalline diamond compact (PDC) bits have the dual advantages of more efficient rock cutting and no moving parts, but experience with PDC bits in geothermal drilling is both scant and unfavorable. Much research and development in hard-rock PDC bits is under way,[8][9] so it is possible that these bits will come into wider use in geothermal drilling.

Tubulars

Because of the low-value fluid (steam or hot water), geothermal wells must produce large fluid volumes and so tend to be larger diameter than oil/gas wells; typical geothermal production intervals are 219 to 340 mm in diameter. Unlike oil/gas wells, geothermal production is from the open hole or through a slotted liner, not through tubing. This means that both drillpipe and casing are usually larger than for oil/gas wells at the same depth.

Drillpipe suffers both erosion and corrosion. Both of these problems are aggravated by high temperature. Erosion is common when air drilling, which is often done to avoid damaging the production interval with mud invasion, but properly hard-banding the tool joints will mitigate erosion. Most drilling contractors and operators establish an inspection schedule, based on experience in the geothermal field being drilled, to track drillpipe condition. Casing problems, other than cementing, usually deal with corrosion and scaling. Brine quality varies greatly, ranging from near-potable in moderate-temperature systems to highly corrosive with high dissolved solids in some high-temperature systems.

Many techniques—cement-lined casing, exotic alloys, and corrosion-resistant cement—have been applied to the casing corrosion problem, which is especially severe in the Imperial Valley. Shallow and hot, CO2-bearing zones there drive an external corrosion rate approaching 3 mm of carbon steel per year, necessitating plugging after 10 to 12 years even after well life was extended by cementing in smaller production strings. Most production wells in the Imperial Valley have been completed or retrofitted with titanium casing, which has proved to be cost effective in spite of its very high capital investment.

Many high-temperature drilling problems with downhole tools and drilling fluids could be avoided or mitigated by using insulated drill pipe (IDP), which delivers cooler fluid to the bottom of the hole.[10] IDP has been demonstrated in the laboratory and in limited field experience, and is commercially available but has not seen significant use by industry.

Drilling fluids

Most geothermal drilling fluids are a fairly simple water/bentonite mixture with possible polymer additives.[11] Large hole volumes and frequent [Lost circulation|lost circulation]] mean that expensive muds have a significant impact on drilling cost. Drilling records from a number of geothermal wells in several reservoirs showed the following typical property ranges.

Density 1.03 to 1.15 g/cm3

Funnel viscosity 35 to 55 sec

pH 9.5 to 11.5

Plastic viscosity 0.01 to 0.02 Pa-s

Yield point 35 to 125 kPa

Well control

Because formations are usually underpressured (pore pressure less than fluid pressure in a full wellbore), influx into the wellbore is rare. There are two primary causes for loss of control:

  • An unexpectedly hot formation is encountered at a shallow depth where the annulus pressure is insufficient to keep the drilling fluid or the formation fluid from flashing to steam
  • Lost circulation causes the fluid level and the pressure in the wellbore to suddenly fall far enough for the same thing to happen.

If complete control is not lost, simply pumping cold water into the wellbore can usually kill the well.

Directional drilling

Neither positive displacement motors nor steering and measurement-while-drilling (MWD) tools operate reliably at high temperature, so most corrections are done at depths where the formation is cooler than 175°C. Kickoffs in higher temperature formations can be done with whipstocks, if they can be oriented with high-temperature survey instruments. High-temperature turbines have been demonstrated and service companies offer “high-temperature” positive displacement motors (PDM), but neither is extensively used in geothermal drilling. If moderate fluid loss occurs while drilling with mud motors, the addition of fresh mud sometimes makes it possible to continue drilling for the life of the bit in a hot hole. Motors are usually burned up on trips back in the hole. High-temperature electronics for steering tools can also be a problem, but technologies exist for operating unshielded electronic components above 260°C.

Cementing

The principal differences between cementing geothermal and oilfield casing are the requirements on the cement itself because of high temperature, and the requirement that geothermal casings are cemented completely to surface to withstand thermal cycling.[12] The major modification in composition of geothermal cement is the addition to standard Class G cement of retardants and approximately 40% silica flour. A fairly typical bill of materials for primary cement of 406 mm casing at approximately 460 m in a geothermal production well is the following: 82 m3 Class G cement mixed 1:1 with perlite and 40% silica flour, 4% bentonite, and 1% CaCl2. The perlite is usually omitted and the Class G cement mixed with 40% silica flour, if there is no loss zone that makes the lighter slurry desirable. Foam cement has also been successful in cementing casing in areas of lost circulation, while latex is extensively used in some areas to offer more corrosion protection in high-CO2 areas.

Geothermal well completions

Thermal cycling in geothermal production and injection wells requires a complete cement sheath around the casing, and high production flow rates (often > 100,000 kg/hr) mean that casing is usually larger in diameter than for many oil/gas wells. Other factors that influence completion design include:

  • Brine chemistry
  • How the well is produced—pumped or self-energized
  • Possible two-phase flow in the wellbore
  • Multibranch completions
  • Presence of lost-circulation zones that would prevent lifting the cement column back to surface
  • Whether the production interval is stable enough to be openhole or must be completed with a slotted liner

Brine chemistry can cause two major problems:

  • Corrosion
  • Scaling

Corrosion can be so severe that titanium casing is economic, even at a cost approaching $1,000/ft, while scaling, either inside the casing or in the production interval, can lead to frequent workovers. Scale is sometimes removed with jets on coiled tubing, but scaling in the wellbore often seals the formation and must be drilled out with an underreamer.

The requirement for a cement sheath to surface means that lost circulation zones must usually be plugged before cementing. Other methods have been used, for example:

  • Stage cementing
  • Nitrogen foam cement
  • Top jobs with a tremie line (small diameter line inserted from the surface into the annulus between casing and wellbore)
  • Perforate and squeeze

These methods are sometimes successful, but the cement job is much simpler and less expensive, if conventional cementing practices will suffice. It is also critical that no water be trapped between the cement and the casing, especially in intervals where one casing is inside another, because the water can become hot enough to flash to steam as the well goes on production and heats up. If the collapse rating of the inner casing is lower that the saturation pressure of the water, the casing will buckle (if the trapped-water location has formation outside it, the fracture gradient is usually low enough to allow the pressure to bleed off into a fracture.)

Case histories of two geothermal wells

To give more intuition for actual Geothermal drilling and completion, case histories for two wells are summarized in Tables 1 through 4. Because certain data related to specific wells are proprietary, the wells are identified only as “steam well” and “brine well.” Both wells were drilled in the mid-1990s, so an inflation factor should be applied to the costs, and both wells were drilled in geothermal fields where there was extensive previous experience. In both tables, ROP means rate of penetration.

  • Table 1—Steam Well Borehole Profile

  • Table 2—Steam Well Bit Summary

  • Table 3—Brine Well Borehole Profile

  • Table 4—Brine Well Bit Summary with Rate of Penetration (ROP)

Steam well

This well was designed to be a two-leg well with casing to approximately 1,500 m and two openhole branches to approximately 3,000 m, but the first leg encountered no steam entries. It was plugged back and two additional branches were drilled (i.e., three holes were drilled from approximately 1,350 to approximately 3,000 m). Although drilling three legs is not required for all wells in this reservoir, it is not uncommon, and drilling records from this well can be extrapolated back to one- or two-branch wells. The hole was drilled with mud to the 1,500 m casing point; then, all branches were air-drilled.

Total time over the hole was approximately 90 days, and total well cost was approximately U.S. $3 million. There was no significant lost circulation in the mud-drilled part of the hole. Other events included milling two windows in the 298 mm casing and four twist-offs—three of them in the air-drilled intervals. Although more footage was drilled than planned, this was considered a relatively trouble-free well.

Brine well

This is a self-energized geothermal production well drilled in sedimentary formations. The well is cased to approximately 640 m and has an openhole production interval from there down to approximately 1,500 m. The corrosive nature of the brine requires titanium casing, but standard practice is to avoid drilling inside this very expensive tubular. Procedure is to drill 375-mm hole to total depth (TD) and flow the test well through 406-mm casing, then run and cement the 340-mm production string inside the 406-mm casing.

Total time over the hole was approximately 50 days (but approximately 10 days went to flow testing the well and cementing the titanium casing), and total well cost was approximately 3.7 million dollars, with approximately 1.4 million dollars of this total for the titanium production string. There were four significant events of lost circulation (total mud lost > 7,000 bbl), all of which were controlled with lost circulation material (LCM). Problems in stage-cementing the 406-mm casing led to a major fishing job. There were no fishing jobs during drilling. This was also considered a relatively trouble-free well.

Additional references

Both the Society of Petroleum Engineers (www.spe.org) and the Geothermal Resources Council (www.geothermal.org) provide searchable databases of publications that include detailed descriptions of geothermal drilling technology. The U.S. Bureau of Land Management provides a summary document describing regulatory requirements for exploration, drilling, production, and abandonment on federal geothermal leases.[13] The Standards Association of New Zealand has printed a 93-page manual that combines regulatory requirements with suggestions on operational practices for drilling, maintenance, repair, and abandonment.[14]

References

  1. ↑ Huttrer, G.W. 2000. The Status of World Geothermal Power Generation 1995–2000. Proc., World Geothermal Congress 2000, Pisa, Italy, 23–37.
  2. ↑ Holligan, D., Cron, C.J., Love, W.W. et al. 1989. Performance of Beta Titanium in a Salton Sea Field Geothermal Production Well. Presented at the SPE/IADC Drilling Conference, New Orleans, Louisiana, 28 February-3 March 1989. SPE-18696-MS. http://dx.doi.org/10.2118/18696-MS.
  3. ↑ Mansure, A.J. 2002. Polyurethane Grouting Geothermal Lost Circulation Zones. Presented at the IADC/SPE Drilling Conference, Dallas, Texas, 26-28 February 2002. SPE-74556-MS. http://dx.doi.org/10.2118/74556-MS.
  4. ↑ Loeppke, G.E., Glowka, D.A., and Wright, E.K. 1990. Design and Evaluation of Lost-Circulation Materials for Severe Environments. J Pet Technol 42 (3): 328-337. SPE-18022-PA. http://dx.doi.org/10.2118/18022-PA.
  5. ↑ Saito, S. and Sakuma, S. 2000. Frontier Geothermal Drilling Operations Succeed at 500°C BHST. SPE Drill & Compl 15 (3): 152-161. SPE-65104-PA. http://dx.doi.org/10.2118/65104-PA.
  6. ↑ Finger, J.T. et al. 1999. Slimhole Handbook: Procedures and Recommendations for Slimhole Drilling and Testing in Geothermal Exploration. Sandia Report SAND99-1976, Sandia Natl. Laboratories, Albuquerque, New Mexico.
  7. ↑ Glowka, D.A. et al. 1996. Progress in the Advanced Synthetic-Diamond Drill-Bit Program. Trans., ASME, 175–180.
  8. ↑ Shopping for the Right Bit. 2001. Hart’s E&P (February): 36–45.
  9. ↑ Finger, J.T., Jacobson, R.D., and Champness, A.T. 2000. Development and Testing of Insulated Drillpipe. Presented at the IADC/SPE Drilling Conference, New Orleans, Louisiana, 23-25 February 2000. SPE-59144-MS. http://dx.doi.org/10.2118/59144-MS.
  10. ↑ Zilch, H.E., Otto, M.J., and Pye, D.S. 1991. The Evolution of Geothermal Drilling Fluid in the Imperial Valley. Presented at the SPE Western Regional Meeting, Long Beach, California, 20-22 March 1991. SPE-21786-MS. http://dx.doi.org/10.2118/21786-MS.
  11. ↑ Nelson, E.B., Eilers, L.H., and Spangle, L.B. 1981. Evaluation and Development of Cement Systems for Geothermal Wells. Presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 4-7 October 1981. SPE-10217-MS. http://dx.doi.org/10.2118/10217-MS.
  12. ↑ 43 CFR Part 3200, Geothermal Resources Leasing and Operations; Final Rule. 1998. Federal Register 63 (189): 52356.
  13. ↑ Standard NZA 2403, Code of Practice for Deep Geothermal Wells, 93. 1991. Wellington, New Zealand: Standards Assn. of New Zealand.
  14. ↑ Whiting, R.L. and Ramey Jr., H.J. 1969. Application of Material and Energy Balances to Geothermal Steam Production. J Pet Technol 21 (7): 893-900. SPE-1949-PA. http://dx.doi.org/10.2118/1949-PA [edit]Noteworthy papers in OnePetro.

Noteworthy papers in OnePetro

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External links

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See Also

Geothermal energy

Geothermal exploration

PEH:Geothermal_Engineering

Category


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