Accueil > EGW 2018 : 6th European Geothermal Workshop > Abstracts > Session 4 : Constructing Geothermal Wells > Session 4 : Oral Presentations

Session 4 : Oral Presentations


The challenges in drilling, testing and operating the latest make-up wells for Hellisheidi and Nesjavellir power plants, SW-Iceland

Bjarni Reyr Kristjánsson, Einar Gunnlaugsson, Gunnar Gunnarsson, Gretar Ivarsson, Pálmar Sigurðsson, Sandra Ósk Snæbjörnsdóttir, Gunnlaugur Brjánn Haraldsson, Eiríkur Þór Jónsson, Sigurður Þorvaldsson, Vignir Demusson, Arnar Bjarki Árnason, Hinrik Árni Bóasson, Sveinbjörn Hólmgeirsson, Benedikt Steingrímsson, Bjarni Steinar Gunnarsson, Gunnar Skúlason Kaldal, Sverrir Þórhallsson

PDF - 275.8 ko
Kristjansson et al.

The Hengill volcanic region in SW-Iceland encompasses vast geothermal resources. It is part of the country’s volcanic rift zone, located at a triple junction where two active rift zones meet a seismically active transform zone. The geothermal area covers about 110 km2 and is one of the most extensive geothermal areas in Iceland. Two geothermal power plants operate in the Hengill region ; Hellisheidi and Nesjavellir, with a combined electrical generation capacity of 423 MWe as well as a thermal energy production capacity of 433 MWth, providing hot water used for space heating in the Reykjavík urban area. The power plants are operated by ON Power which is a subsidiary of Reykjavik Energy.

The Hellisheidi geothermal power plant is located 20 km southeast of Reykjavík, on the southern flanks of the Hengill central volcano. It is a combined thermal energy and electricity power plant consisting of six 45 MWe high pressure and one 33 MWe low pressure turbine generator units and a 133 MWth thermal energy production unit. It was commissioned in stages between 2006 and 2011 (Hallgrímsdóttir et al. 2012). The Nesjavellir power plant is located in the northeastern part of the Hengill Area. It was commissioned in 1990 and enjoyed 15 years of gradual development until it reached a final installed capacity of 120 MW electric and 300 MW thermal. At this time 62 production wells and 17 reinjection wells have been drilled in the Hellisheidi area and 30 production wells and 8 reinjection wells in Nesjavellir.

Because of the fast pace development of the Hellisheidi power plant expansion decisions were taken early in the well drilling campaign. It was therefore impossible to adapt the project to the reality that later emerged when reservoir data and production history emerged. The field was smaller and more heterogenous than predicted resulting in a suboptimal result of the well drilling campaign.

High production density, especially in the center of the field, resulted in a productivity decline (Gunnarsson and Mortensen, 2016) which was met by connecting the neighboring Hverahlid field with a 5 km pipeline. Before that plans had called for a separate power plant development at the Hverahlid field. Those plans were consequently cancelled. According to Reykjavik Energy’s reservoir model it will still be a challenge to maintain the production capacity of the combined fields. Financial risk assessments together with various production scenarios predicted by the reservoir model showed that a drilling campaign with very poor results will still give a positive economical outcome if optimal productivity is maintained at the power plant (Gunnarsson, et al. 2017). Consequently, ON Power contracted Iceland Drilling after a bid round to drill 10 wells in 2017-2019. The company is currently drilling well number five in the drilling campaign which is the ninth make-up well since the completion of Hellisheidi power plant in 2011. Three of the nine wells were drilled in the Nesjavellir field. The first two wells of the current campaign have been tested with extraordinary good results and all five wells are expected to be on-line in the near future.

Standard well design and testing equipment had been used successfully up until recently where the team has encountered more powerful wells than before. Due to very high pressure, temperature and flow rates the well design and standard procedures for commissioning new wells have been revised. Still, harnessing the power of these wells been a challenging task for our team and we are still dealing with some unresolved issues.

Full-Scale Horizontal Test-Rig for Simulation of Deep Geothermal Drilling

Rodrigue Freifer, Lisette Hayn, Joachim Oppelt


PDF - 341.7 ko
Freifer et al.

Well construction in geothermal application is cost intensive. The process of drilling alone can amount to more than 50% of the budget of an Enhanced Geothermal System (EGS) project1. Reasons for this are the challenges that occur during the drilling job. Examples of these challenges are drilling in hard rock and complex wellbore geometries. The consequences are often severe downhole vibrations that lower the rate of penetration (ROP), cause damage to the downhole tools and eventually lead to drill string failure. Therefore, understanding the source of these vibrations will help in their mitigation and will provide a direct contribution to the reduction of the overall costs of an EGS. Field measurements are not adequate for reliable and repeatable research. To directly observe the influences of specific parameters, a full-scale test-rig is needed. This paper presents the first test performed with a drilling simulator that meets these requirements.

To investigate the problems of drill string vibrations, the German Center for High-Performance Drilling and Automation, Drilling Simulator Celle, has recently developed a horizontal test rig with the overall aim of drilling cost reduction. In the test rig, the lowest part of the drill string, about 20 m long, is placed inside an extended borehole run in order to drill a selection of rocks that are positioned in a 5 m long pressure vessel, as shown in figure 1.

The test-rig covers all essential systems needed for a drilling job. Rotation is provided by a synchronous torque motor that delivers a torque of 10,000 N.m. Up to 26 tons of weight-on-bit (WOB) are created through a hydraulic system that pushes the BHA into the rock. For hole cleaning, two triplex pumps constitute the circulation system that produces a flow rate of up to 3,000 L/min with a drill string pressure of 200 bar. Besides, the annulus pressure is limited to 100 bar.

Tests are being conducted on the test-rig within a government funded project called “ROP Optimization for Deep Geothermal Wells through Systematic Analysis of Downhole Vibrations in Laboratory Experiments” with the acronym “OBS”. The tests are providing information about bottom hole assembly (BHA) behavior during the drilling process, as well as test-rig behavior. It is important to take the behavior of the test-rig into consideration because of the parasitic vibrations that it introduces. This allows for matching the measurements obtained during the experiments with measurements acquired from the field.

The first drilling test was carried out with a 6 ¾” sized BHA in a “Hold” configuration. The drill bit was a Polycrystalline Diamond Compact (PDC) with double row cutters and a size of 8 ¾”. The rock type was chosen to be “Obernkirchner Sandstone” with an unconfined compressive strength (UCS) of 98 MPa, which is considered moderately strong rock2. In addition, operating parameters of the circulation system were held constant at a pressure of 75 bar and a flow rate of 2,250 L/min. The mud weight was chosen to be 1.03 sg.

The drilling test was executed in stages where one WOB value was held constant while the RPM was stepped up from 40 to 140 RPMs. After completion of the RPM steps, the WOB was increased and the RPM steps were carried out again until a WOB of 6 tons was reached.

For dynamic BHA measurements, accelerometers were included in the PDC bit allowing the logging of tangential, lateral and axial vibrations. The monitoring system of the experimental setup included accelerometers on the extended borehole run as well as on the rock chamber. RPM and position sensors are responsible for obtaining the rotational speed and the ROP, respectively. However, the torque is calculated by the frequency converter of the motor. Additionally, the effective WOB is calculated from the pressure inside the hydraulic cylinders and the annulus pressure.

First operational results showed that the steps applied for RPM and WOB were held constant throughout the test, which proves the build of a good control system. Moreover, torque and ROP values show the reasonable magnitudes for such a BHA-Bit-Rock combination. In addition, it is visible that low WOB and high RPM lead to inefficient drilling by using the concept of mechanical specific energy for rock removal. On the other hand, high WOB and low RPM operation will increase vibration levels and shock provocation.
Furthermore, modal analyses using the finite element method were conducted for both BHA and test-rig. The simulated natural frequencies were matched with the measured frequencies resulting in a mean error of 1.8% for the BHA and 2.32% for the test-rig. This indicates a good understanding of the test-rig, along with its boundary conditions.

Overall, the results demonstrate the ability of the test-rig to recreate and monitor downhole vibrations.

Several experiments are being planned that involve different BHA configurations alongside different formations. In order to make the experiment even more realistic, the OBS project is looking into adding the effect of the missing part of the drill string using high performance actuators. The concept of combining the BHA in a Hardware-in-the-Loop (HIL) simulation is being researched, for it will be able to emulate the drilling of a real horizontal well bore. Making the experiments as realistic as possible will be key to identify the effect of the different parameters on the drilling process and therefore develop better mitigation strategies while aiming for the maximum ROP.

A combined thermo-mechanical drilling method : Field implementation and demonstration

Edoardo Rossi, Martin O. Saar, Philipp Rudolf von Rohr

PDF - 571.6 ko
Rossi et al.

Global electricity production from geothermal heat relies on finding cost-effective solutions to enhance drilling of deep geothermal wells. Conventional drilling methods, based on mechanical removal of the rock material, feature high drill bit wear rates and low rates of penetration, especially in hard rocks (Angelone & Labini, 2014). This, in turn, results in increased specific well costs (€/MWh) and therewith a decreased economic appeal of deep geothermal projects. Hence, in order to favor/promote the use of deep geothermal heat for electricity production, advances in drilling performance for deep wells must be attained/achieved. In this respect, alternative drilling concepts are investigated worldwide with the aim of boosting the drilling performance and reducing the overall project costs. An interesting approach to effectively remove hard rock materials is thermal spallation drilling. This method uses a hot jet, impinging on the rock surface, to induce high thermal stresses which are responsible for crack initiation and propagation and therewith they are able to trigger the thermal spallation phenomenon at the rock surface. This excavation mechanism showed substantially higher penetration rates in hard rock materials, compared to conventional rotary drilling methods. Nevertheless, the thermal spallation onset cannot be established when soft materials or stress-relieving fractured rock formations are encountered.

Therefore, with the aim of improving the drilling performance in both soft and hard rock materials, we investigate a combined drilling method where conventional, rotary drilling is assisted by a heat source (Rossi et al., 2018). In this manner, during drilling in hard rock materials, thermal spallation can be used to achieve improved penetration rates, compared to conventional mechanical drilling methods. On the other hand, when softer rocks are encountered, the material is thermally treated with the flame before being removed by the drilling cutters. A prior thermal weakening of the material therefore facilitates the mechanical removal of the rock and enhanced drilling performance can be achieved. Laboratory experiments demonstrated that the thermal assistance induces considerable improvements for the subsequent removal of the rock material. In order to prove the applicability of thermal spallation drilling in conventional drilling systems and the related performance improvements compared to state-of-the-art methods, a field demonstration of the technology is carried out in a full-scale drill rig.

Experiments on drilling performance
Experiments in the laboratory are conducted to show the drilling performance improvements of assisting conventional drilling via a pre-treatment of the rock material. In order to show this, we investigate the interaction of a drilling cutter with a soft sandstone and a hard granite after thermally treating the material and compare the results to untreated material conditions. The combined thermo-mechanical drilling method is experimentally modelled by a thermal treatment of the rock samples (a sandstone and a granite) which includes a heating process until a maximum temperature of 800°C, followed by a fast water cooling until ambient temperature. After this, scratching experiments are performed on the rocks and the two main cutting performance parameters, removed rock volume and wearing rate, are measured. A comparison between the proposed thermo-mechanical drilling method and conventional mechanical drilling is carried out by analysing the cutting performance parameters for the material after the thermal treatment and under baseline conditions.

In Fig. 1, the cumulative removed rock volume and the worn tool volume are shown along the distance of the performed scratch. As shown in Figs 1.a and 1.b, the drilling performances in granite are considerably enhanced by thermally treating the material prior to the mechanical removal performed by the drilling cutter. Furthermore, the wear rate of the drilling cutter is significantly reduced for the whole scratching distance range. The same experiments are performed in the sandstone material, as shown in Figs 1.c and 1.d. This softer rock, shows overall improved removed rock volumes when the material is thermally treated in the oven, especially for large scratching distance values.

Thus, the presented results show that the combined thermo-mechanical drilling method features substantially increased penetration performance, compared to conventional drilling method. This is particularly evident in the hard granite material, where the rock removal is greatly facilitated with additionally lower induced wear rates of the drill cutters. Overall, laboratory experiments on the combined thermo-mechanical drilling concept showed evidences for greatly improved drilling performances, especially for the hard granite material. Hence, the field implementation of the drilling technology aims to show the applicability of a thermal assistance to conventional drilling systems with a focus on the occurring geothermal well cost reduction.

3 octobre 2018