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Final Conference - Vilnius, Lithuania
Final Conference - Vilnius, Lithuania
12-15 February 2008 Le Méridien Villon
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Drilling Stimulation and Reservoir Assessment - State of the art and challenges ahead













Drilling operations are performed in order to open up geothermal reservoirs for energy exploitation. During the drilling process, the drilling rig has to fulfil various functions. It has to rotate the drilling bit in order to achieve abrasion of the drilled formations. It has to ensure circulation of the drilling mud, so as for the drill cuttings to be transported up the well bore, it has to provide traction power, for the drill string to be pulled out of the well, and to control the weight on the drill bit during drilling.
The choice of an appropriate drilling rig is one of the most important decisions in well planning. The rig should have a sufficient safety margin and fit in its technical specifications (hook load, rig horse power, etc.) to the specific well planning. In order to avoid unnecessary costs, standard oil field bit sizes and casing diameters should be used wherever possible. 

At the same time particular necessary differences in well design between hydrocarbon wells and geothermal wells have to be taken into account. Due to the high production rate in geothermal wells for example, well diameters, and correspondingly diameters of injection and production strings have to be bigger in geothermal wells.

A rig management system which has been developed by many drilling companies is a key to attaining a cost effective well. This directs the drilling personnel of different positions to be familiar with their respective task in the day to day drilling operation. Familiarity with safety, well control, drill string design, cementing calculations, mud formulation and experience in dealing with numerous drilling problems, coupled with dedication by rig personnel will for sure result in a cost effective drilling operation.  

With only very few exceptions a drilling mud will circulate within the well bore during the drilling operations. The drilling mud has to fulfil various main functions within the drilling process. First of all, it serves in transporting cutting material away from the drill bit, up the well bore. Secondly it helps to stabilize the well bore by means of balancing the pressures at the borehole wall, and thirdly it might be used for cooling the well. In order to enable a continuous operation, a sufficient supply of drilling mud has to be ensured. Mud pumps have to be dimensioned such that they are capable of providing drilling mud in adequate quantity. Mud cleaning facilities have to be installed and, if necessary, mud cooling services as well.

The drilling personnel should be properly trained and familiar with all aspects in the drilling operation. Training of rig personnel should be a continuous process as this will enhance their capabilities in producing an economical well. 


After Sperber et al. 2005, the drilling techniques applied in exploiting geothermal reservoirs do not fundamentally differ from those applied in drilling hydrocarbon (oil or gas) wells. They are to be found in standard textbooks like Bourgoyne (1986), Nguyen (1996), Jackson (2000) or Nguyen et al. (2006). The main fields to which particular attention has to be paid when drilling geothermal wells in sedimentary environments are borehole diameter, directional drilling and techniques targeted at avoiding formation damage. 

In order to obtain flow rates in geothermal wells, which are high enough to secure an economically viable operation of a geothermal power plant, the borehole diameter has to be big enough. Thus diameters of geothermal wells are generally bigger than the diameters of corresponding hydrocarbon wells of comparable depth. This has implications not only for drilling costs, but also for issues of borehole stability, since a given formation with certain parameters of strength, and a certain, generally anisotropic, stress field, the formation is more prone to borehole breakouts, the bigger the borehole diameter is. This becomes even more important if the well is deviated. It is therefore recommended to carefully investigate the in situ stress field and borehole stability ahead of well planning, such that well path, mud weight and casing program can be chosen accordingly.

In order to hit the subsurface target zone with a sufficient degree of accuracy, it is generally necessary to drill directionally. This is accomplished through the use of bottom hole assembly (BHA) configurations, instruments to measure the path of the well bore in three dimensional space, data links to communicate measurements taken downhole to the surface, mud motors and special BHA components and drill bits. Drilling parameters like weight on bit (WOB) and rotary speed are also used to deflect the bit away from the axis of the existing well bore. The most common way to point the bit in the direction one wants to drill is through the use of a bent in a downhole steerable mud motor assembly. The bent points the bit in a direction different from the axis of the well bore, when the entire drill string is not rotating. By pumping mud through the mud motor, the bit turns, while the drill string does not rotate, allowing the bit to drill in the direction it points.

The drilling bit generally has to be chosen according to the geological formation to be drilled. In sedimentary environments this will in most cases be a TCI bit, which might or might not necessary have hard metal inserts. Polycrystalline Diamond (PCD) Bits have been use successfully when drilling uniform sections of carbonates and evaporates, that are not broken up with shale stringers (Bourgoyne et al., 1986) Although successful use of these bits has also been reported from sandstone, siltstone and shale formations, PCD bits can certainly not be recommended generally in these formations.

Although a high drilling speed is generally desirable in order to keep drilling costs low, for technical reasons it is not always recommended. While drilling ductile formations like clay or claystone for example, it may be recommended to reduce drilling speed, and, if necessary, also the WOB in order to keep the bit in a cutting mode, and not turn into a pressing mode.

Differential sticking occurs, when the drill string is held against the well bore by a force. This force is created by the imbalance of the hydrostatic pressure in the well bore and the pore pressure in the permeable formation (Bowes, 1997). When the hydrostatic pressure is greater than the pore pressure, the difference is called the overbalance. The resultant force of the overbalance acting on an area of drill string is the force that sticks the string. Differential sticking might occur with a stationary or slow moving string, when an overbalance is present, across a permeable formation, in a thick filter cake, when a contact exists between the string an the well bore. This means deviated sections of wells in permeable, sedimentary environments are particularly prone to differential sticking. Any action to reduce the aforementioned causes will reduce the risk of differential sticking.

Drilling salt formations is a particular challenge in its own, where highly plastic salt formations can easily cause casing collapse. This is a particular risk when salts are found deep in the well, since the plasticity of salt increase with temperature. Careful attention has to be paid to the selection of drilling speed, adjustment of mud weight, and choice of an appropriate casing. 

In order to achieve the highest flow rates possible from the geothermal well, formation damage due to, for example, mud invasion has to be avoided. When drilling in sandstone dominated formations it is desirable to avoid mobilisation of clay minerals. For this purpose it is recommended to drill under balanced or near balanced. Special drilling mud should be used which reduce clay mineral mobilization. A marble-flour might be added to the drilling mud which will help building up a thin mud cake, which protects the reservoir formation. If necessary this thin mud cake might later easily be removed through acidization. 

Thermally induced stress on the casing during hot water production has to be considered and casing damage generally has to be prevented.  This commonly requires a complete cementing along the whole profile. 

In order to prevent fluid circulation behind the casing within the overburden, cementation up to the surface is essential. The bond between tubing, cement and the rock has to withstand the thermal tensions and the pressure changes during the entire life span of the well. Blast furnace cement has turned out to be very suitably. The process of cementation up to the surface represents a high pressure load for the unlocked formations. The cement slurry density can be adapted to these conditions by specific additives. In Groß Schönebeck cement slurry densities of 1300 kg/m³ were reached with sufficient firmness.

Usually cementing of a well will be performed from the bottom to the top, but in case this is not successful, a squeeze cementation can be performed from top of the well to, for example, the former cement infiltration zone. It is generally recommended to verify the successful placement of the cement. This can either be achieved by means of conventional cased hole logging operations or by thermal logging.

Attention has to be paid in case gas bearing formations have to be drilled. The mud weight has to be chosen high enough, as to avoid the gas to enter the drilling mud. Potentially gas bearing formations also have to be considered when planning the casing program for the well.


In this paragraph drilling technology applied to shallow (<3500 m) high-temperature drilling (defined as >180°C at 1000 m and not exceeding 320°C) in volcanic systems will be described. Volcanic systems are in one way or another associated with volcanic activity. The heat sources for such systems are hot intrusions or magma. They are most often situated inside, or close to, volcanic complexes such as calderas and/or spreading centers. Permeable fractures and fault zones mostly control the flow of water in volcanic systems.

The majority of all high-temperature geothermal wells in Iceland are drilled to 1500–3000 m. Many of them are drilled as directional wells. The trajectory chosen is rather similar, a kick off point (KOP) at 300–600 m after landing the anchor casing and then a build-up to 30–45° after which the inclination is maintained to total depth. The resulting horizontal displacement is commonly 700-800 m. Directional wells are preferred for environmental reasons, and the targeting of near-vertical structures is easier.

The drilling rigs used for geothermal drilling are oil well rigs with 200 - 450 t hook load capacity and were equipped with rotary table drives, but now many of the rigs have a top-drive. To be able to maintain cooling while tripping into a well is very important as the bits and tools used are destroyed or have a shorter life is they are exposed to high temperatures. 

In order to optimize drilling performance and thus reduce drilling costs, it is recommended to look at a curve potting depth vs. days that the drilling-job has taken. Any “flat spots” where there is no advance in depth for several days will clearly show, which will indicate that there may be potential for operational improvement. 

Mud motors are required for directional drilling, but they were also found to improve the rate of penetration a lot, contrary to the experiences of drilling granites in Soultz. In Iceland, mud motors have therefore also been used in drilling vertical holes. 

Mud motors have parts of elastomers (rubber) that cannot take high temperatures. This problem is addressed by cooling the well through the circulation of drilling mud. This works so efficiently, that a temperature of less than 100°C can be maintained in a 2000 m deep well even though the reservoir temperature is over 300°C. Effective cooling of the well also allows Measurement While Drilling (MWD) tools to be run deep in the hole. 

The BHA is the lowest part of the drill string. In the past there was a drill bit and on top of it the drill collars to exert pressure to the bit and then stabilizers to keep the string in the middle of the hole. Now the BHA usually contains a shock absorber, the mud motor, the Measurement While Drilling (MWD) tool, and then the drill collars with a hydraulic jar to free the string should it get stuck. On top of the drill collars there is a key-seat reamer and to smooth the transition over to the normal drill pipes a few “heavy-wate” drill pipes. 

The life of drill bits has steadily improved especially the ones with journal bearings and with hard metal inserts as “teeth” and to maintain diameter (“gauge protection”). These are considerably more expensive but can be rotated over 1 million rounds and drill perhaps up to 1000 m without being replaced. Polycrystalline diamond bits (PCD) have found some use in geothermal drilling. They can drill fast even without a mud motor, but the rotary torque is usually twice as high and life shorter than for a good tri-cone bit. 

Geothermal wells are designed to enable safe drilling into geothermal reservoirs and then to allow production of steam and water over several decades. In volcanic systems, geothermal fluids are compatible as far as the scaling chemistry is concerned, so that the produced fluid can come from any depth, as long as the temperature requirements are met. 

This means that the open hole part of geothermal wells is usually over 1000 m long and is supported by a slotted liner. This allows any fluid to enter the well. Most geothermal wells have 3–5 cemented casing strings, the deepest one to 700–1500 m (production casing). The expected productivity of the reservoir and target output of the well primarily influence the diameter selection.

For most HT geothermal wells the selection stands between a 9-5/8” production casing and a 13-3/8” casing. In case the well productivity is high enough, large wells with a 16” production casing are drilled as well. If the permeability of the reservoir is excellent then the diameter of the wells becomes the limiting factor as far as output is concerned. The output is roughly proportional to the cross-sectional area of the production casing. The most common casing strings used are: 7” or 9-5/8” (for slotted liner), 9-5/8” or 13-3/8” for production casing and then 18-5/8”, 22-1/2” or 24” etc. The reason for the many casing strings is to support the hole and especially to provide safety in controlling blow-out´s. The last cemented casing string, the production casing, also has to consider the minimum target temperature by reaching at least that deep into the reservoir. As a very rough “rule of thumb” for each section of the well being drilled, the casing needs to cover 1/3 of the target depth for that section. For example in a 2400 m hole with three cased sections the production casing should reach 800 m, the anchor casing to 267 m and the surface casing to 89 m. Note that by targeting the well to go deeper, all casing strings need to be longer. 

The detailed and final casing program is planned once the expected temperature and pressure profile is known for a particular drilling location. This has to include considerations on the depths at which the target temperature is reached, and the general geological conditions.

For very permeable wells and where the boiling point is within the cemented casing, wells have successfully operated without a slotted liner, so called “barefoot” completion. This is also the completion of choice, when drilling into shallow steam caps, where “kicks” (sudden eruptions) are most common in the 100–300 m interval where there is boiling ground. For such wells, it is difficult to landing the slotted liner, which may in cases not be possible at all due to “kicks”.  

The casing steel grade takes notice of the H2S found in the geothermal fluid and usually grade API K55 or N80 is used. 

Connections were mainly screwed API buttress but VAM and Antares are now also found. In Iceland the 18-5/8“casing and 22-1/2” are butt-welded to allow small clearances in the 21” and 24” drilled holes. All low temperature wells in Iceland use butt-welded connections and the casing is API line pipe.

By standardizing on two to three casing program sizes the inventory of drilling tools becomes simpler and the drilling become routine. This in time contributes to lowering costs. The casing program is virtually the same for directional wells as for vertical ones.

In Iceland water based bentonite mud is used while drilling with large bits >17-1/2“, to obtain adequate hole cleaning. The low-solids water based mud (SG 1.02) is a “simple” one made with high yield bentonite clay (Wyoming bentonite), and the additives are only caustic to maintain high pH, and a dispersant. In order to control artesian overpressure in wells, a high density mud of SG 1.4 is occasionally prepared.

In the productive part of the well, water-only is the preferred drilling fluid, perhaps occasionally using polymer or mud-pills to clean fill-ins. It is felt that less formation damage is caused by the use of water and also it is of course less expensive than mud and allows uninterrupted drilling after the desired loss zones are encountered. 

Lately methods that attempt to overcome the formation damage have been applied by what is called “balanced drilling” (aerated drilling) or sometimes “underbalanced drilling” (Hole, 2006). It requires large air compressors, a rotating head, and a separator on the flow-line. Similar amounts of water are pumped into the hole as in normal drilling, together with the air. Compressed air and soap is mixed with the drilling fluid (usually water only) thereby reducing the density so much, that the pressure inside the well will be no greater than the respective reservoir pressure. Thus no fluid or sand should be lost to the formation. 

When wells are drilled into steam dominated reservoirs, using compressed air alone is the preferred method. After intersecting steam it flows out of the well together with the air. Remarkably the rate of penetration for normal rotary drilling goes up as well, offsetting in part the increased cost. On average, these wells are reported to have up to twice the output of conventionally drilled wells in the same field (Hole, 2006).

Cementing is one of the most critical and time consuming operations of the drilling effort. Zones of unwanted circulation losses were treated in the past by stopping soon thereafter and cementing to heal the loss, taking 1-3 days, but now it is common practice to bypass these zones. Good cementing can nevertheless be obtained by inner-string cementing up to the loss zone. Flow of water top down in the annulus then keeps the loss zone open and thereafter the annulus is filled up by “squeeze cementing” pumping down to the loss zone. Recently “reverse” cementing where the cement is pumped down the annulus, has been successfully tried. In some countries “foam” cement is used to lessen the slurry density and loss of circulation material added to block the losses. 

The cement has to withstand the high temperatures and the chemical environment and to that end API grade G cement with 40% silica flour added (ground quartz, -325 mesh) is most commonly used.

Additives such as retarders, fluid loss, friction reducer, antifoam, are then selected based on the expected temperature, size of job etc. 

In Iceland expanded perlite has been used to reduce the cement slurry density to 1.65 and in other countries “micro spheres” or “foaming” by injection of gas or air are similarly used to reduce the collapse pressure exerted on the casing from the cement column and to decrease the chance of a breakout. 


In order to optimize drilling cost effectiveness, rotary drilling is applied wherever possible. Only for a short section, directional drilling with downhole motor is used for kick off and build up of the planned deviation angle although no improvements of drilling performance are to be observed when applying downhole mud motors. Due to frequent grain size changes at short distances, alterations and numbers of fractures no PCD bits are used. Slick, packed or pendulum bottom hole assemblies were applied.

Natural salt (sodium chloride) is used as weighting agent, as long as possible - Sodium chloride is an inexpensive weight agent, easily soluble and non toxic. Caustic soda is used to raise ph level and to minimize corrosion. If required, Bentonite is used as viscosifying agent for transport of cuttings. Settling pools and Polymers are used to separate fluid and cuttings.  In order to thicken the mud for disposal, Cuttings and cement were added.

A “free floating” casing is installed which is supported at the bottom by open hole casing cupper nickel packers, and a short cementation. The casing is “free” at the wellhead using high temperature fluorelastomer ring seal pack offs to allow for estimated casing growth/shrinkage. With a depth of 5 km wells at the technical limit is reached for a free casing well completion.

A light HMR cement is used which is capable to resist aggressive brines at high temperatures.

Gyro surveys are performed at kick off, and whenever confirmation of well trajectory is required. MWD are used while drilling directional to monitor the trajectory at early stages of kickoff. CBL – VDL tools and USI are run in order to inspect for cementation, casing thickness, scaling, corrosion and ovalisation.


The most prominent challenges during drilling of geothermal wells in Larderello are: high temperatures of more than 300 °C, highly corrosive reservoir fluids, a failure of the drill strings, often due to stuck pipe, total loss of circulation when very high permeability fracture zones are encountered during drilling and problems in setting cementing and maintaining the casing ( Brunetti et al., 1970, Bottani et al., 1985, Lazarotto et al., 2005).

In the presence of high temperature formations, the temperature of the drilling fluid is controlled by means of cooling operations, which includes pumping the slurry to remove the drilling cuttings, and injecting water in the annular space between drill string and casing.

Failure of the drill string often occurs due to stuck pipe. One solution to this problem can be to reduce the unitary stress on the drill string by increasing its diameter. Utilizing only such drill strings, which have been inspected and certified on a regular basis. Using a top drive drilling system significantly reduced the risk of getting stuck in the well, thus avoiding the risk of costly rescue operations, or even a partial loss of the well. Apart from this, it may also considerably contribute to reducing tripping time by adding multiple drill pipes (up to three) at a time.

In case very high permeability fracture zones are encountered during drilling, total loss of circulation (TLC) might occur. If plugging the formation proves to be impossible, these formations are drilled with water while accepting the total loss of circulation which might require a flow rate of 40 – 80 m³. In order to reduce fresh water consumption for TLC, geothermal steam condensate from a nearby power plant can be used for this purpose, if available. 

Since the well casing has to withstand extremely high temperatures once the well is under production, a good cement bond along the entire casing length is essential in order to prevent casing collapse. Achieving a good cement bond can be a problem in areas where intensive fracturing is found. These absorbing zones can be plugged, using injections or squeezes with accelerating additives. Where this does not work, a diesel oil cement bentonite plugging technique (DOCP) can be the solution, in cases where the fracture zone occurs deep enough, so that no pollution of fresh water occurs. Running cement bond logs serves in identifying zones of poor cementation, which might lead to casing collapse during rapid heating, or to stress corrosion. These threats may be addressed by drilling a hole in the formation and than re-cementing. These measures might be avoidable entirely, by means of creating conditions for setting the casing and the cement such that an acceptable level of mechanical stress on the casing is guaranteed for the entire lifetime of the well (Bottani et al., 1985)

In the past corrosion in drilling has been part of the numerous problems experienced in the conduct of drilling whether it is oil and gas or geothermal drilling operations. It is the decomposition of the metallic state of an element. The different types of corrosion are due to physical and chemical causes and if not addressed properly will eventually affect the drilling performance. The effect of corrosion in drilling is costly as it may cause drilling string twist off and fishing and sometimes loss of the entire well, in case the problem persists.  It is always a good practice to follow the developed guideline in dealing with corrosion. The practice may add cost to the well but will pay off as a critical or major problem which costs the company more is avoided. If for some reason a severe corrosion problem exists, engineers and field personnel should be able to prevent a major catastrophe by closely observing changes in the parameters. For example: a drop in pressure in drilling means there is something that is not normal i.e. pump problem, leak in fluid system, change in fluid density etc. or there may be a crack in the drill string due to thinning because of corrosion. Early detection can prevent major problems. 

In Larderello, steam scrubbing with an alkaline solution is a mandatory practice in order to prevent accelerated corrosion of any carbon steel equipment and failures of the turbine blades. According to the degree of superheating, steam scrubbing is carried out downhole, at the wellhead or at the power plant inlet. Since the integrity of the casing near the wellhead is of paramount importance, the use of a corrosion proof production casing in the vicinity of the wellhead may be indicated (Lazarotto et al., 2005).

In many cases, particularly in sedimentary environments and in deep granites, the drilling operations will not open up the geothermal reservoir under such conditions that an extraction of geothermal energy is economically viable without any further measures. Geothermal wells often have to be stimulated, in order to increase well productivity. Well stimulation might be performed hydraulically, chemically or thermally. 


Since the early 1980s, research at various sites confirmed that shearing rather than tensile fracturing is the dominant process (Pine & Batchelor, 1984; Baria et al., 1999; Cornet, 1987). Natural joints, favourably aligned with the principal stress directions, fail in shear. As a consequence, formations with high stress anisotropy and hence, a high shear stress, should be best candidates for hydraulic fracturing in low permeable rock.
Knowledge about the stress regime is of great importance to understand or even to predict the hydraulic fracturing process (Cornet et al., 2007; Evans et al., 2005). Borehole breakouts, borehole fractures, microseismic events and stimulation pressures have been evaluated to confine the orientation and amplitude of the principal stress components.

One method to reduce the risk of creating shortcuts is the isolation of intervals in the borehole and the successive stimulation of these intervals. This way, a larger effective fracture area can be obtained than with one massive stimulation over a long open hole section. Such strategy is also favourable to reduce the risk of creating larger seismic events. 

Cases of induced seismicity have been reported from hydraulic stimulation programs in geothermal wells, but not all geological formations are prone to these events. Induced seismic events, which could be felt at the surface, have been reported from hard rock environments. Since the permeability in these formations is a fracture-permeability, the pressures generated to frac the formation can only diffuse through the fracture and fault network, which will lead to a reduction in effective stress. In sedimentary environments, due to their matrix porosity and permeability, elevated pressures will not focus on fracture and fault pathways, but diffuse through the porous matrix. A potentially considerable sedimentary coverage of a hydraulically stimulated hard rock formation will also damp induced seismic events.

Controlling the reservoir growth while stimulating or circulating is an important issue for all projects in low permeable rock (Baria, 2006). Microseismic monitoring gives 3-D time-resolved pictures of event location and magnitude from which the fractured rock volume can be inferred. This method has evolved to the key technique to map the reservoir in HDR projects (Niitsuma, 2004; Wallroth et al., 1996). In current projects (Soultz, Cooper Basin-Australia) the microseismic event distribution serves for the determination of the target area for new wells. More recently, microseismic monitoring has become important to detect and to control larger seismic events, which might occur during stimulation in geological active areas (Bommer et al., 2005).	HYDRAULIC STIMULATION - SEDIMENTS - GROSS SCHÖNEBECK 

The geometric orientation of a geothermal well system has to follow conflicting goals. The wells should be located in such a way, that the pressure in the reservoir will not drop significantly during production, while at the same time a thermal short circuit between the wells, has to be avoided. 
In HDR systems, the orientation of the wells is typically in the direction of the maximum horizontal stress with hydraulically induced fractures propagating to each other in an impermeable rock matrix, whereas hydrothermal systems are generally designed in such a way, that hydraulically induced fractures are oriented parallel to each other. This alignment admits flow through the permeable reservoir rock between the fractures and avoids a short circuit between the wells. 

In deviated wells convergent flow issues can be expected as a vertical fracture with a small width will intersect the well bore, which means, only a few perforations will accept the majority of the flow. To counterbalance this effect, it is recommended to keep the perforation intervals small while using a high shot density perforating technique. In order to reduce the effect of convergent flow further, the slickwater treatment should be ended with a high proppant concentration to increase the fracture width in the near-well bore region and improve the inflow performance.

The gel-proppant treatments will typically start with a DataFRAC to obtain information about the fracture pressure, the friction and tortuosity of the perforated interval, and the leakoff behaviour of the reservoir. In this DataFRAC one will first pump an uncrosslinked gel which will give an indication if any near-well bore problems exist. This will then be followed by pumping a crosslinked fluid which will give an idea of leakoff as well as help to predict closure pressures, frac geometry and whether there is any indication of pressure dependent leakoff.
The MainFRAC treatment is an injection of gel loaded with proppants with a stepwise or ramped increase of proppant concentration with a high viscous crosslinked gel into the fracture. The result of the treatment mainly depends on the achieved fracture characteristics – its dimensions and its conductivity. The slurry rate and the concentration of proppants added and their variation as a function of time will determine this.  

An adjustment of slurry rate and proppant concentration during the treatment is possible and often necessary to omit a screen-out of the well, and in case the pressure progression causes concerns of a potential failure of the treatment. 
Waterfrac treatments and gel-proppant treatments can also be combined (hybrid treatments, e.g. Sharma et al., 2004).	HYDRAULIC STIMULATION - VOLCANICS - GROSS SCHÖNEBECK

Flow rate during waterfrac treatments can be held constant during the whole treatment or vary in a cyclic manner. Simulations have shown that the impact of high flow rates for the fracture performance is higher, even if high flow intervals are limited in time, compared to a constant flow rate (e.g. Zimmermann et al., 2007). 
Scaling can be avoided, by adding salt like KCl to the water, or acid to reduce the pH prior to injection. An abrasive agent such as sand can be added during the high flow rates in order to enhance the treatment. Using a proppant suspending agent gives the proppant mechanical suspension while travelling through the frac. This will increase the fracture height and allow the proppant to move to the end of the fracture. Using a friction reducing agent in the fluid instead of a guar based gel can be considered, if gel is not an option (e.g. in acidised environments).	HYDRAULIC STIMULATION - GRANITES - SOULTZ

Different stimulation concepts have been applied to enhance the productivity of geothermal wells in crystalline rock. These techniques can be subdivided with respect to their radius of influence. Techniques to improve the near well bore region up to a distance of few tens of meters are chemical treatments, explosive stimulation and thermal fracturing. The only approved stimulation method with the potential to improve the far field, up to several hundreds of meters away from the borehole, is hydraulic fracturing.

The concept of hydraulic fracturing as applied in low permeable rock differs from the one usually applied in sedimentary rock with respect to fluid type, fluid volume and proppants. In crystalline rock it is common practice to inject only water without proppants, but much larger volumes than in sedimentary rock are pumped. Large fracture areas have to be stimulated in crystalline rock whereas the improvement of the near well bore region is usually the main target in permeable sedimentary rock. 

At the Soultz test site, an important relationship was found between the injection rate during stimulation and the productivity of the well after stimulation (Jung and Weidler, 2000). The productivity of the wells appears to increase linearly with the injection rate during stimulation.	HYDRAULIC STIMULATION - METAMORPHICS - LARDERELLO

After Cataldi et al. (1983) hydraulic stimulations are mainly performed in the Larderello geothermal field in order to convert production wells which are no longer commercial into injection wells. Numerical modelling studies have been carried out with the intention of investigating fracture creation or propagation of fracture systems. Practical hydraulic stimulation tests indicated that the stimulation results are encouraging, but cannot be considered totally adequate for practical purposes.

Hydraulic injection tests performed resulted in the creation and propagation of a fracture zone, a gradual shift of skin from positive to negative values, an improvement in injectivity from increasingly longer injection time and a hydraulic behaviour typical for fractured media. However, the results are confined to a small part of the reservoir. More satisfactory results will most likely only be reached when artificial fractures intersect and connect zones of naturally high permeability.


In the volcanic rock environment in Iceland, a stimulation process involves a combination of induced pressure and temperature changes, performed in order to clear existing flow passages and create new ones. 

Stimulation processes normally start with water circulation through drill-string followed by pumping cold water into the well, sometimes at elevated wellhead pressures. This is interrupted by intervals of non-activity, during which the well is allowed to heat up towards its natural temperature state. This way, a combination of thermally induced cracking forces and pressure impulses can increase the permeability of existing fractures and possibly create new fractures or conducting pores.

Stimulations at low temperature fields (below 150°C reservoir temperature) primarily involve pressure changes induced either directly at wellhead or down-hole, where inflatable packers (seals) are placed to more effectively address deeper well sections. Air-lift pumping is, furthermore, commonly used in low-temperature stimulation operations. 

The ideal evaluation of the effect of stimulation is achieved by a combination of pressure, flow and temperature monitoring at wellhead with temperature, pressures and well bore imaging down-hole. In this way, the overall effect of stimulation is monitored along with observations of local fracturing leading to well bore enhancement. 

A more detailed description of stimulation methods including case histories from Iceland is given in Axelsson et al. (2006), ENGINE publication presented at Ittingen, Switzerland.

Economic exploitation of enhanced geothermal systems is strongly dependant on natural or induced mineral precipitation and associated decrease in permeability of the system. One solution to this problem consists in injecting a reacting fluid into the wells, in order to dissolve the secondary minerals scaled on the casing or sealing fractures, to increase the permeability. Until recently, most experiences in chemical stimulation came from the oil industry.

Choice of the acid and any additives for a given situation depends on the underground reservoir characteristics and on the specific intention of the treatment, for example near well bore damage removal, dissolution of scale in fractures. HCl and HF are two acids reacting quickly with carbonates and silicates. However, the objectives of acid treatment are to increase porosity and permeability of the medium, deeply in the formation. 

This second main technique, is performed above fracturing rates and pressures. Etching of the created fractures provides well stimulation, not just damage removal. The aim is to change the future flow pattern of the reservoir from radial to linear to effectively stimulate the reservoir and increase production. The key to success is the penetration of reactive acid along the fracture. To achieve deeper penetration in fracture acidizing, it is often desirable to retard acid reaction rate.
Compared to carbonate reservoirs, the acidification of a sandstone reservoir, requires a specific procedure. The objective of acidizing sandstone wells is to increase permeability by dissolving clays and other pore plugging materials near the well bore. Clays may be naturally occurring formation clays or those introduced from drilling, completion or workover fluids.
Three sequences are needed for the treatment of a sandstone reservoir: preflush, main flush and overflush. The preflush is performed most often with a HCl solution, first to displace the formation brines. The main flush is used to remove the damage and most often, a mixture of HF and HCl or organic acids is pumped into the well. Finally the overflush performs the displacement of the nonreacted mud acid into the formation and of the mud acid reaction products away from the well bore. 

Current practices of sandstone acidizing are linked to concentration and ratio of HCl and HF acids, as well as the volumes pumped into the formation during the different phases, which are dependant on the formation rock mineralogy. Corrosion inhibitor is always necessary and it must be added to all acid stages (preflush, mainflush, and overflush). 

Coiled tubing is a very useful tool for improving acid placement. Coiled tubing is of less use in fracturing acidizing because of pumping rate limitations. It is still best to pump fracturing treatments through larger strings, such as production tubing. In larger open hole sections, acid diversion is important, otherwise only the interval, which breaks down or open fractures first will be treated. Diversion can be achieved with packers.

Nearly all geothermal wells that are acidizing candidates have been damaged by either drilling mud solids and drill cuttings lost to the formation fractures or by scale (calcium carbonate, silica, calcium sulphate, and mixtures). 

The only acid additives necessary in a geothermal acid job are corrosion inhibitor and inhibitor intensifier, as well as high-temperature iron-control agent.
In all documented cases, acidification occurred in the three usual main steps, preflush (HCl), main flush (HCL-HF mixture) and overflush (HCl, or KCl, NH4Cl or freshwater).
In successful geothermal well acidizing, the choice of water/acid and HCl/HF ratios as well as retardant agents are key factors. A summary of the main chemical stimulation experiments carried out in geothermal fields is given in Table 1, showing variable results. 

Geothermal field	Number of treated wells	Improvement factor of injectivity
Bacman (Philippines)	2	1.4 - 4.4
Leyte (Philippines)	3	1.9 – 7.1
Tiwi (Philippines)	1	2.6
Mindanao (Philippines)	1	2.8
Salak (Indonesia)	1	2.6
Berlín (El Salvador)	5	2.8 – 9.9
Las   Las Tres Virgenes (Mexico)	2	2.5 - 3.1
Los   Los Azufres (Mexico)	1	2.8
Beowawe (USA)	1	2.2
The Geysers (USA)	1	no effect
Coso (USA)	30	24 wells successful
Larderello (Italy)	5	4 - 12

Table 1 : Results of HCl-HF treatments for scaling removal and connectivity development in high temperature geothermal wells



Many different types of well tests can be performed, and the choice depends wholly on the information which is being sought. Being clear about the objectives of the test is paramount in deciding about the type of test to carry out. These objectives are

•	Evaluate existing fracture systems
•	Assess fractures induced by hydraulic stimulation
•	Investigate Matrix transport properties 
•	Determine Reservoir boundaries 
•	Reservoir compartmentalization

A Pressure drawdown survey, in which the flowing bottomhole pressure is measured while the well is flowing, is a primary method of measuring productivity index (PI). Establishing a stable rate over a long period can be difficult, creating some uncertainty in the analysis.

Pressure build-up surveys measure the bottom hole pressure response during the shut in period which follows a pressure drawdown. This is useful for measuring reservoir properties and near well effects such as skin. In this test, the flow rate is known (zero).

Interference tests between two wells are used to estimate the transmissibility (kh/μ) of the formation in the interval between the wells. A pressure change is created at the active well by shutting in or opening up the well, and a pressure gauge in the closed-in observation well awaits a pressure response, the arrival time of which can be used to estimate transmissibility.

A pulse test is a version of the interference test, but attempts to provide enough information to allow the interpreter to eliminate the effects of noise and gauge drift in pressures (to which the interference test is prone) as measured at the observation well.

A Stepped flow and stimulation test basically is a small hydraulic stimulation, aimed at reducing near well bore inlet and outlet hydraulic impedances. It consists of injecting into a well at constant flow rate, and recording the pressure rise within time.

In a Multi-rate-pre-fracturing-hydraulic-test, the injection flow rate is increased in steps. In each step the flow is continued at constant rate until the injection pressure attains an asymptotic value. The test delivers valuable information on transmissibility, the significance of turbulence and details of fracture dilation Murphy et al. 1999.

A Multi-rate-post-fracture-performance-test is performed to determine the hydraulic properties of the stimulated fracture system. They are performed like the corresponding pre-fracture tests except that the flow rates are usually much higher, and the test duration is longer.

Long-term injection and production tests in a single well are especially useful for determining the outer hydraulic boundary conditions of the stimulate fracture system. It can help to predict the long-term fluid loss from the reservoir during operation.

Generally, pressure differences during the test phase should be kept sufficiently  small, in order to remain in the hydraulic mode instead of frac mode.

All off the aforementioned test procedures were developed in order to test wells which produce a single well fluid. In the more general case of multiphase flow, multiphase effects have to be taken into account in test interpretation. After Horne, 1995, it is almost always better to design a well test ahead of time, to avoid multiphase conditions during the test. 


Tracer testing is an efficient method to detect and characterize hydraulic connections between deep geothermal wells, to understand the migration of injected and natural fluids, and to estimate their proportions in discharged fluids, their velocities, flow rates, residence times. Depending upon the tracer test methodology, useful information on transport properties and hydraulic connections essential for heat exchange or for fluid re-injection in geothermal reservoirs can be obtained from the data collected during such tests after their interpretation and modelling (Sanjuan et al., 2006, Ghergut et al., 2007). 

Following the required information, several types of modelling approach can be used to analyze the tracer Return-Curve data from a slug injection: signal processing codes such TEMPO based on a model of dispersive transfer (Sanjuan et al., 2006) or using the moment analysis method (Shook, 2005), hydraulic or hydrodynamic codes such as SHEMAT (Blumenthal et al., 2007) or TOUGH2 (Pruess et al., 2000), coupled hydro-mechanical codes, etc.

As the physicochemical behavior of the tracers under given reservoir conditions (high salinity fluid, very low redox potential, low pH, etc.) is not always well known, the use of a minimum of two tracers (or comparison with a natural tracer or laboratory experiments) is recommended.  

Among the tracers recommended in the literature for using at high temperature conditions, we can distinguish the following compounds

•	Liquid phase tracers

•	naphthalene (di, tri)sulfonates (nds, nts, ns) family: 1,5-, 1,6-, 2,6-, 2,7-nds, 1,3,5- and 1,3,6-nts, 1- and 2-ns  (Rose et al., 2001);
•	aromatic compounds: sodium benzoate or other benzoates (Adams et al., 1992). Fluorobenzoic acids are water tracers widely used and preferred in oil reservoirs       (J. Muller, IFE, pers. comm.);
•	fluorescein (T < 260°C ; the other organic dyes are not recommended).

The use of inorganic and radioactive tracers is limited because of the high natural background of the halides (Cl, Br, I…) and difficulty in obtaining permits for radioactive tracers. 

•	Vapour or two-phase tracers
•	Alcohols (isopropanol, butan-2-ol, etc.) and hydrofluorocarbons (volatile low molecular weight compounds R-134a (CF3CH2F) and R-23 (CHF3), Adams et al., 2001) as geothermal vapour-phase tracers, and perfluorocarbons as geothermal vapour-phase tracers. Perfluorocarbons are gas tracers widely used and preferred in oil reservoirs (J. Muller, IFE, pers. comm.);
•	homologous series of short-chain aliphatic alcohols as geothermal two-phase tracers: ethanol, n-propanol (Adams et al., 2004; Mella et al., 2006a and b).
Naphthalene sulfonates have been or are used in numerous deep volcanic, granite and sedimentary geothermal fields. Alcohol tracers (isopropanol, butan-2-ol, etc.) have been used as steam-phase tracers in New Zealand (Lovelock, 2001) and at the Matsukawa vapour-dominated geothermal field in Japan (Fukuda et al., 2005). Halogenated alkanes and hydrofluorocarbons (R-134a and     R-23) have been used as tracers in vapour-dominated systems such as The Geysers in the United States (Adams et al., 2001).  Ethanol and n-propanol were successfully used as two-phase tracers at the Coso site in United States (Mella et al., 2006a and b).

Inter-well tracer tests using organic compounds such as Na-benzoate, 1,5-, 1,6-, 2,6 and  2,7-nds were conducted at the Soultz granite site during hydraulic stimulation operations (Sanjuan et al., 2006). A tracer test using fluorescein also accompanied a 5-month fluid circulation loop between GPK-3 (injection well) and GPK-2/GPK-4 (production wells) in 2005.
In the deep crystalline basement of the German KTB site, a combination of short-term and long-term tracings using uranine, nds compounds and tritiated water accompanied a long-term hydraulic and seismic testing program (Ghergut et al., 2007).


Once a geothermal reservoir has been opened up for energy extraction through one or several wells, a reservoir assessment should be performed, in order to estimate the amount of energy which will be extractable from the reservoir. To mine the available resource in a sustainable manner, a reservoir management or development plan should be implemented, which in most cases will have to be updated during the course of production to account for growing insight into the field and understanding of the reservoir. A monitoring program has to be implemented according to reservoir specific requirements.


Geothermal Reservoir assessment can be defined as the broadly based estimation of supplies of geothermal heat that might become available for use, given reasonable assumptions about technology, economics, governmental policy and environmental constraints (Muffler and Christiansen, 1978). Such reservoir assessment in terms of reserve estimation and valuation is currently not yet common practice within the geothermal community. 

Like in the Mineral- and in the Hydrocarbon industry, any quantification of the reliability of the physical resource is generally performed using a classification into various classes: proven, probable and inferred reserves for example, with associated cumulative probabilities (P10, P50, P90). Clear criteria have been formulated by various Authors (Clothworthy et al., 2006, Sanyal et al. 2005) for such classifications. 

Up to now there are no standards for a geothermal reservoir assessment, but various approaches exist. From these, only a volumetric reserve estimation, and a valuation based on numerical reservoir simulation can be considered as generally appropriate for geothermal reservoirs (Sanyal, 2005). The first Method gives a basic but sound estimation, which can be used in an early state, already ahead of an actual reservoir development. But it is associated with a certain degree of uncertainty. The second method heavily depends on comprehensive input data including an advanced production history, but it delivers the most accurate and reliable results. 

In a volumetric reserve estimation, first the spatial extent and the thickness of the reservoir are determined from geophysical and geological exploration results, and, if applicable, the information from existing wells. In a second step, the “heat in place” about a certain reference level, for example ambient temperature or injection temperature, is calculated from reservoir volume and average temperature. After Sanyal, (2005) this is followed by estimating the recoverable heat energy reserves using a certain recovery factor, which describes the part of the heat in place, which can be produced at the well head. Electrical reserves are determined form thermal reserves und consideration of the relevant conversion efficiency. Finally the field capacity is calculated from the recoverable energy reserves, for an assumed power plant life and capacity factor. Generally, such a volumetric reserve estimation can be applied in several different ways which have been described and critically reviewed by various authors (Muffler, 1979, Sanyal et al., 2004, Sanyal and Henneberger 2004.) The aforementioned method is not applicable for steam dominated reservoirs, but for these cases an alternative formulation is given by Sanyal (2005).

A comprehensive review of numerical modelling procedures for geothermal reservoir assessment is given by Hochstein (1988). A numerical simulation starts with setting up a numerical model according to the geometry of a first conceptual reservoir model, which contains all information from previous assessments (static reservoir parameters, pressure and temperature data from wells and dynamic reservoir parameters from well tests). The model is calculated into an initial equilibrium. After that the induced heat and mass transfer is computed for the period of known production. The computed time variable parameters are compared with the observed values, and if necessary, the model (permeability distribution and/or model geometry) are modified in order for the simulation results to best fit the production history. A numerical simulation is obviously only relevant and applicable for reserves which were classified as proven.

Since the volumetric reserve calculations are prone to overestimation, they should be based on conservative assumptions of the input parameters (Sanyal et al., 2005). It is generally stated (Clothworthy et al., 2006, Sanyal et al., 2005) that reserves should only be classified as proven, if, and only if prospects for the commercial productivity from the reservoir have been demonstrated.


For each geothermal system and for each mode of extraction there exists a certain level of maximum energy production E0, below which it will be possible to maintain constant energy production for a very long time. E0 is not known a priori, but can be estimated, by modelling, on the basis of available data, (Axelsson et al. 2004). In many cases several decades of experience have shown that by maintaining the production below a certain limit, a geothermal system reaches a certain balance, which may be maintained for a long time. The overall generating capacity of geothermal systems is often poorly known, and they often respond unexpectedly to long term production. Careful monitoring and modelling as well as energy efficient utilization are essential ingredients of a sustainable geothermal reservoir management. 

The reason for overexploitation of geothermal reservoirs often is a poor understanding of the geothermal system due to lack of monitoring and data collection. Rybach (2007), performed FE calculations at EGS Models, investigating two different expoitaion scenarios. These investigations  showed that with lower extraction rates, longevity of the resource, and thus sustainable production, can be achieved and still generate as much energy as from excessive production.

In order to maintain a sustainable production Management of geothermal fields should always include common management of nearby wells which might be utilized by different users. The negative experiences of the Geysers field, USA, with 22 power plants and a cumulative capacity of 1531 MW should be avoided, where a drastic pressure drop in the field caused the steam production to be insufficient for all the power plants and production declined steadily. The pressure drawdown due to overexploitation of the Geysers geothermal field could meanwhile notably be diminished since the water reinjection programme has started.	CORROSION & SCALING 

Alkalinity and CO2 together with temperature control the corrosion in the geothermal production wells. It is a general belief that the corrosion is usually controlled by the formation of protective films of corrosion products or an efficient corrosion inhibitor and that the corrosion rate is low. The corrosion in the injection well is currently controlled by applying a corrosion inhibitor and oxygen scavengers. 

With regard to CaCO3 and SiO2 scaling it will be advantageous to reduce the pH in the injection water from ca. 4.8 to 4.3. This will affect the corrosion rate in the injection well, and it is recommended to carry out an experimental program to evaluate the effect this will have on corrosion. It has to be documented that the corrosion inhibition will be sufficiently effective at the lower pH.  

There is a range of monitoring systems that can be used for online monitoring of corrosion rates. The challenge is to place them at the most relevant positions. Weight loss coupons can be applied during circulation tests. It is also recommended that iron counts are carried out regularly. It might also be worthwhile to evaluate the possibility of using hydrogen monitoring as corrosion surveillance on the production wells.


Monitoring of geothermal fields and their production currently is no standard procedure. Goal, purpose and design of any geothermal monitoring program depend to a great deal on the particular geological environment and production conditions. Potential monitoring parameters are the conditions of state, reservoir pressure and temperature, fluid chemistry, flow rate (spinner surveys), seismicity, gravity and the electrical potential. An adequate monitoring program helps to avoid overexploitation of the geothermal reservoir, leads to a better understanding of the geothermal system and allow a more reliable reservoir modelling( Axelsson et al., 2004).

Monitoring of the chemical composition of water and steam discharged from wells in exploited geothermal fields provides valuable information on the response of the reservoir to the production load. (Arnorsson and Gudmundsson, 2003). Withdrawal of deep reservoir fluid generally induces recharge, which may alter the chemistry of the fluid, especially if a significant portion of the recharge water has a very different chemistry. Monitoring of the dilution trends can provide information about the rate of lateral movement of the invasion front.

Geophysical monitoring can be a useful tool, helping to understand pathways within the reservoir as well as fluid migration, and thus aid in optimizing reservoir exploitation strategies (Rivas et al., 2005). Apart from these purposes, seismic monitoring has also proven to be a potentially very useful exploration tool.  But this has up to now mainly been reported from volcanic environments. The Analysis for fracture density can indicate potentially fractured areas as exploration targets (Simiyu, 2000). Axelsson et al. (2006) report on a case, where earthquakes at a much deeper depth than the injection horizon indicated that a hydraulic connection exists to deeper Horizons. This meant that the source area for the particular field was much bigger that assumed up to that point, and the field had the potential for much wider geothermal use. 

Any monitoring of a geothermal reservoir should commence at the time, the actual production begins, at the latest (Hunt, 2000). It should be performed frequently enough, that natural variations can be distinguished from exploitation induced changes. The data have to be archived and documented in such a way, that they are accessible for the potentially changing interpretation personnel over the entire field life.
Id: 36
Place: Le Méridien Villon
Vilnius, Lithuania
Starting date:
13-Feb-2008   14:00
Duration: 20'
Contribution type: talk
Primary Authors: Mr. SCHULTE, Thomas (GeoForschungsZentrum Potsdam)
Presenters: Mr. SCHULTE, Thomas
Material: slides Slides
Included in track: Oral Session - Synthesis and Best Practices, Priorities, Research needs

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