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Pramudyo, Eko (Tohoku University) | Watanabe, Noriaki (Tohoku University) | Takeyama, Sho (Tohoku University) | Goto, Ryota (Tohoku University) | Miura, Takahiro (Tohoku University) | Hattori, Kohki (Tohoku University) | Sakaguchi, Kiyotoshi (Tohoku University) | Komai, Takeshi (Tohoku University)
Our previous studies on hydraulic fracturing in granite at 200°C to 450°C under triaxial stress condition revealed that infiltration of low-viscosity water at near-/super-critical temperatures stimulates preexisting microfractures and creates dense fracture networks which is favorable for extraction of geothermal energy. Presently, fracturing experiments have been carried out at similar conditions to examine feasibility of low-viscosity supercritical carbon dioxide (SC-CO2) adoption for application at various geothermal conditions. In this study, three fracturing experiments were conducted on cylindrical granite samples at 200°C and 450°C, with a range of differential stress, where liquid CO2, which was preheated to the experimental temperature before entering the borehole, was injected at 1 ml/min. At 200°C, 85 MPa axial stress and 40 MPa confining stress were applied. Meanwhile at 450°C, 90 MPa axial stress with 40 MPa or 25 MPa confining stress was applied. As a result, 50 MPa breakdown pressure was observed at 200°C. At 450°C, 47 MPa and 17 MPa of breakdown pressure were observed for the experiment at 40 MPa and 25 MPa confining stress respectively. As the theory predicted that in the case of non-penetrating fluid, breakdown pressure will be approximately twice the magnitude of confining stress, these low breakdown pressures indicated fluid penetration. Furthermore, borehole pressure profiles suggested that pore pressures were close to borehole pressure. In addition, X-ray CT on the samples revealed that complex fracture patterns were developed. It has been discovered that stress states at breakdown events were close to Griffith failure criterion. The low-viscosity SC-CO2 has allowed stimulation of preexisting microfractures so that the rock failed in accordance to Griffith theory, in which fractures generated in various locations. Hence, favorable complex fracture patterns were generated. The results demonstrated the feasibility of SC-CO2 adoption to replace water in fracturing application at a wide range of geothermal conditions, due to its capabilities to return low breakdown pressure and to induce complex fracture network as well as to sequester CO2 at certain amount.
In order to make the world’s energy consumption sustainable there is a need for reducing emissions of CO2 and to shift towards renewable energy sources. Geothermal energy has a large potential in certain parts of the world. One example is Iceland, where the reservoir in IDDP-2 is around 427°C and 340 bar at a final well depth of 4650 m. This makes it attractive as a geothermal reservoir of high enthalpy supercritical water with the potential for conversion of large amounts of high temperature deep geothermal energy.
Production from the IDDP-2 is scheduled to start in 2019, and hence the fluid composition is not known. Using available data for nearby wells, and in particular IDDP-1, an estimate can still be made. A combination of high temperature and pressure, the presence of corrosive agents (such as HCl and H2S), a low pH and reducing conditions gives rise to challenges related to material selections.
This paper summarizes part of a desktop case study that addresses corrosion and scaling issues for conditions relevant for the IDDP-2 geothermal well. The reservoir and well data are based on temperature measurements inside the well and assumptions on a hydrostatic reservoir. The total depth of the well is 4650 meters. Based on this a model is set up for temperature and pressure profile along the well. Knowledge gaps, such as lacking solubility data and corrosion rates at supercritical conditions are pointed out.
The background for this paper is the desired utilization of deep geothermal energy in general and the IDDP-2 well (Iceland Deep Drilling Project1) in special. IDDP is aimed to achieve production of geofluids from a field with supercritical water conditions. An attractive feature of production from a supercritical reservoir is that it potentially can generate a higher power output than conventional high-temperature wells.2 In theory, it is possible to produce such a field as dry superheated steam, i.e. with no water condensation during normal production. This has desirable features, which will be discussed later.
Corrosion testing of austenitic stainless steel, UNS S31603 (AISI 316L), was conducted in flow-through reactors during early stages of lab setup development with the aim to obtain a superheated steam environment with H2S/CO2/HCl at 350°C and 10 bars. The test fluid; aqueous solution with the corrosive species was preheated, boiled and superheated in preheater before entering the reactors. But due to regular high-volume injection periods of the aqueous solution into the preheater and insufficient thermal insulation surrounding the test unit, a liquid droplet transportation into the reactors and condensation of the test fluid in the reactors was experienced. After the corrosion testing, the corrosion rate of the samples varied quite significantly, and different corrosion forms were observed. The corrosion rate was determined with weight loss analysis and the corrosion forms were analyzed with SEM, XEDS, XRD and light microscope. The aim of corrosion testing was to simulate high temperature geothermal environment i.e. IDDP-1 (Iceland Deep Drilling well #1) conditions where previous on-site corrosion testing of some alloys had been conducted. The experiment casts a light on different corrosion behavior of the UNS S31603 at boiling/superheated/condensation conditions which is to be expected during the heat-up and discharge period of deep drilled wells as well as working conditions (superheated).
In the first Iceland Deep Drilling Project (IDDP-1), in-situ weight loss experiment was conducted for some corrosion resistant alloys and carbon steels. Superheated geothermal steam was obtained from the well with 450°C and 140 bars at wellhead. The weight loss experiments were done in a test chamber and an exhaust pipe with throttled steam from the wellhead where the temperature was 350°C and pressure 12-13 bars . The geothermal fluid (see Table 1) from IDDP-1 contained corrosive components such as CO2 and H2S and additionally HCl and HF gases and where the fluid had approximately pH = 3 upon condensation . Silica precipitated from the fluid in the exhaust pipeline due to pressure drop (and temperature drop) and hence silica covered the corrosion samples during the testing as can been seen in figure 1. All the corrosion samples had very low corrosion rates i.e. the corrosion resistant alloys and generally low corrosion resistant carbon steel.
The Salton Sea KGRA has long been known for its power generating potential, however, the corrosivity of the hypersaline fluid has limited power generation as well as the production casing material choices. In the 1990’s UNS R56404 (titanium Grade 29) was utilized very successfully to line nearly all of the energy producing wells in this field. The material proved to be an excellent choice and has given 20-25 years’ service life to date. Despite its excellent performance, Grade 29 is a high strength titanium alloy that is expensive to manufacture and finish. Recent wells (2012 and beyond) have utilized other (non-titanium) materials that were less expensive upfront, but appear to be degrading at a much faster rate than the Grade 29 titanium alloy. To date, these newer wells have required repairs in as little as 2-3 years after start-up. Several new alloys that will address both the cost and performance issues seen in this geothermal field have recently been developed. This paper will highlight the corrosion performance of these new alloys, along with their more cost effective manufacturing processes.
The development of supercritical geothermal wells will require materials of construction that can withstand the harsh corrosive environment at these elevated temperatures. Titanium is not usually considered under these conditions due to the lack of experience and the perceived high cost of the alloys. However, operators in the Salton Sea region have come to depend on titanium for production well casing over the last 25 years. Titanium is one of the only alloy systems that shows minimal corrosion and a higher resistance to scaling. In addition, the low thermal expansion and modulus of titanium significantly reduces the compressive stress on connections, thus typically limiting the strain developed during thermal cycling to the elastic region.
The goal of harnessing high power geothermal wells has been underway at several sites around the world since 1980.1 Two deep wells were drilled in Iceland under the guidance of the Iceland Deep Drilling Project (IDDP). The IDDP-1 was drilled by Landsvirkjun in 2009 and became the hottest geothermal well in the world at that time.2 However, the aggressive conditions caused extensive corrosion of the well casing materials.3 HS Orka drilled the second deep well, IDDP-2 in 2017. This became the deepest and hottest well in the world, but yet again; the materials of construction were not able to withstand the environment.4 A third well, IDDP-3, is under the direction of Reykjavik Energy and is now under discussion as to the materials of construction. The goal of IDDP is to achieve 450°C supercritical steam which will produce 50MW power with 7in. OD well casing.
The second deep geothermal well drilled in the Iceland Deep Drilling Project (IDDP) at Reykjanes was completed in the year 2017. The final depth of the IDDP-2 well reached 4650 m depth, with a bottom hole temperature of 427°C and a pressure around 340 bar. The well was injected with cold tap water for stimulation after being completed. Temperature measurements were performed during an intermediate heat up in the well where no cold water injection was performed. A carbon steel injection pipe was implemented to the bottom of the well to ensure cold water and improved stimulation into the deepest part of the well. Extensive corrosion damages were discovered on the lowest part of the injection string when retrieved. Multiple axial cracks were also observed on the joint ends in a 600-meter interval of the pipe, from 4650 up to 4000 m depth. Failure analysis of damaged parts of the injection pipe with visual inspection and microscopic examination revealed extensive uniform and pitting corrosion. The analyze indicate that the high temperature and relatively high oxygen content in the cold water used for injection and contact with corrosive reservoir fluid caused the severe corrosion. The analysis of the cracks and hardness measurements of the joints indicate that sulfide stress corrosion cracking is the most likely cause of failure due to combined effect of thermal stresses, corrosive environment and susceptible material.
The drilling of the second deep geothermal well drilled in the Iceland Deep Drilling Project (IDDP) at Reykjanes geothermal field was successfully completed in the beginning of year 2017. The previously drilled RN 15 production well, 2500 m deep, was used as the base for the IDDP-2 well. The final depth of the IDDP-2 well reached 4650 m depth, with a bottom hole temperature measured to be 427°C and a pressure around 340 bar. The bottom of the IDDP-2 well reached fluid at supercritical conditions and became the deepest geothermal well in Iceland. After completion of the well a 3,5” drill string was implemented into the very bottom of the well. The well was injected with cold tap water for stimulation within the injection drill string. The drill string was made of carbon steel (API 5DP PSL1 grade G-105). The flow rate of the cold water was 15 l/s inside the drill string and 45 l/s in annulus (space between injection drill string and well casings and liner). During the cold water injection period the pumping was stopped and the water in the well was able to heat up for several days during two separate heat up periods, in March and May 2017. Figure 1 shows measured temperature of the well during injection. Damages were discovered in the IDDP-2 casing at 2300 m depth. From Figure 1 it can be stated that reservoir fluid is flowing into the well at 2300 meter because there is a step in the temperature at this point. During the time from when the drill string was first inserted to the well there have been different flow rates for the cold water injection to the well to improve thermal stimulation. In certain periods there has also been no injection to allow periodic heating of the well as stated previously. Pressure measurements show overpressure in the bottom of the well compared to the assumed hydrostatic pressure in the reservoir during the heat up periods. This leads to downwards flows internally in the well towards the lowest reservoir zones and the lowest section of the drill string. This shows the possibility for reservoir fluids to be in contact with the outside of the drill string at least in certain periods. The temperature within the drill string was recorded during one heat up period; it reached 384°C at the bottom and 254°C at 4000 m after 5 days of heating up.1
Although thermal heavy oil recovery methods are extensively used, no unified and standardized basis exists for selecting materials and configuring intermediate (production) casing/connection systems for these extreme-service applications. Thermal intermediate casing systems must accommodate a wide variety of mechanical and environmental loads sustained during well construction, thermal service at temperatures exceeding 200°C, and well abandonment. Numerous operator- and field-specific designs have been used with good success and only a few isolated challenges, but industry's use of its operating experience to calibrate tubular design bases for future wells has been limited.
This paper identifies the benefits and components of a unified casing system design basis for thermal wells, aimed to be technically comprehensive, inclusive of the available elements of industry's collective knowledge and experience, and adaptable to technological advancements. The technical element of the unified basis broadly relates to the engineering foundation used to make three primary design selections: material, pipe body, and connections. For each design selection, the paper provides an overview of the associated technological challenges and the current state of the industry in addressing those challenges, including the commonly-adopted design approaches. Key performance considerations include integrity during well construction, connection thermal service structural integrity, pipe thermal service integrity and deformation tolerance, connection sealability, and casing system environmental cracking resistance. Where applicable, the paper identifies interdependencies that exist between design selections (for instance, the impact of pipe material selection on the thermally-induced axial load that must be borne by the tubular and connection), and discusses mechanisms for accounting for those added complexities in the design.
Ultimately, the intent of this paper is to provide a framework for referencing existing technical knowledge and for considering further development and field benchmarking work that will reduce the technological uncertainty and increase simplicity in thermal casing system designs. Industry will benefit from a unified engineering approach that offers operators sufficient flexibility to accommodate application requirements and prior experience.
A 3-week corrosion testing of UNS N06625 was conducted in supercritical fluid at 350°C and 10 bars. The aim of corrosion testing was to simulate high temperature geothermal environment i.e. IDDP-1 conditions where previous on-site corrosion testing of UNS N06625 and other alloys had been conducted. The simulated environment had lower concentration of H2S and CO2 in the steam comparing IDDP-1 environment. In addition, no silica scaling was precipitated on the samples nor HF was used in the simulated experiment. The corrosion rate was determined with weight loss comparison and the corrosion forms were analyzed with SEM, XEDS and light microscope. The result of the simulated experiment shows that some localized corrosion is occurring and the corrosion rate of UNS N06625 in simulated environment is similar to the corrosion rate observed in IDDP-1.
In the first deep drilled well (IDDP-1) in the Iceland Deep Drilling Project in-situ weight loss experiment was conducted from an exhaust pipe from wellhead of the borehole for several corrosion resistant alloys and carbon steel types. Superheated geothermal steam was obtained from the well with 450°C and 140 bars at wellhead. The weight loss experiments were done in exhaust pipe with throttled steam from the wellhead where the temperature was 350°C and pressure 12-13 bars . The geothermal fluid (see Table 1) from IDDP-1 contained corrosive components such as CO2 and H2S and additionally HCl and HF gases  Due to the pressure drop, large amount of silica precipitated in the exhaust pipeline and hence silica covered the corrosion samples during the testing. All the corrosion samples had very low corrosion rates i.e. the corrosion resistant alloys and generally low corrosion resistant carbon steel. The corrosion resistance of N06625 was measured to be less than 0.001 mm/year but localized cracks and pits were observed on sample after testing. From the corrosion testing, it was concluded that the silica scaling prevented general corrosion but promoted under deposit corrosion  of UNS N06625. Same was concluded from the results of the testing of other samples.
Stefánsson, Ari (HS Orka) | Duerholt, Ralf (Baker Hughes, a GE company) | Schroder, Jon (Baker Hughes, a GE company) | Macpherson, John (Baker Hughes, a GE company) | Hohl, Carsten (Baker Hughes, a GE company) | Kruspe, Thomas (Baker Hughes, a GE company) | Eriksen, Tor-Jan (Baker Hughes, a GE company)
The typical rating for downhole measurement-while-drilling equipment for oil and gas drilling is between 150°C and 175°C. There are currently few available drilling systems rated for operation at temperatures above 200°C. This paper describes the development, testing and field deployment of a drilling system comprised of drill bits, positive displacement motors and drilling fluids capable of drilling at operating temperatures up to 300°C. It also describes the development and testing of a 300°C capable measurement-while-drilling platform.
The development of 300°C technologies for geothermal drilling also extends tool capabilities, longevity and reliability at lower oilfield temperatures. New technologies developed in this project include 300°C drill bits, metal-to-metal motors, and drilling fluid, and an advanced hybrid electronics and downhole cooling system for a measurement-while-drilling platform. The overall approach was to remove elastomers from the drilling system and to provide a robust "drilling-ready" downhole cooling system for electronics. The project included laboratory testing, field testing and full field deployment of the drilling system. The US Department of Energy Geothermal Technologies Office partially funded the project.
The use of a sub-optimal drilling system due to the limited availability of very high temperature technology can result in unnecessarily high overall wellbore construction costs. It can lead to short runs, downhole tool failures and poor drilling rates. The paper presents results from the testing and deployment of the 300°C drilling system. It describes successful laboratory testing of individual bottom-hole-assembly components, and full-scale integration tests on an in-house research rig. The paper also describes the successful deployment of the 300°C drilling system in the exploratory geothermal well IDDP-2 as part of the Iceland Deep Drilling Project. The well reached a measured depth of 4659m, by far the deepest in Iceland. The paper includes drilling performance data and the results of post-run analysis of bits and motors used in this well, which confirm the encouraging results obtained during laboratory tests. The paper also discusses testing and performance of the 300°C rated measurement-while-drilling components – hybrid electronics, power and telemetry - and the performance of the drilling tolerant cooling system.
This is the industry's first 300°C capable drilling system, comprising metal-to-metal motors, drill bits, drilling fluid and accompanying measurement-while-drilling system. These new technologies provide opportunities for drilling oil and gas wells in previously undrillable ultra-high temperature environments.
ABSTRACT: Geothermal drilling environments are often hostile to well materials, especially in magmatic settings where properties of well casing and cements may rapidly change as a result of high temperatures and chemically active formation fluids. Prolonging the lifetime of such geothermal wells is one of the key challenges to achieve a commercially successful geothermal projects. This study aids analysis of critical stress conditions for well integrity and initiation of damage in wellbore cement during operation of geothermal wells using a combination of analytical and discrete element models. The analytical models are used to determine wellbore stresses that are applied to 3D discrete element models of typical well sections. Wellbore models and boundary conditions are based on subsurface conditions encountered in well IDDP-1 of the Iceland Deep Drilling Project. Possibilities of using the discrete element models to test the behavior of well materials under realistic pressure and temperature conditions in this type of wells are explored. The workflow may be used to test novel well materials and designs at different depths.
Maintaining long term wellbore integrity in high temperature environments is one of the key challenges for the commercial success of geothermal projects. Geothermal drilling environments are often hostile to well materials, especially in magmatic settings where properties of well casing and cements may rapidly change as a result of high temperatures and chemically active formation fluids. Prevention and mitigation of well integrity problems under these conditions is aided by detailed knowledge of critical conditions for wellbore failure and by analysis of special requirements for well materials. The integrity of wellbore cement is particularly important in high temperature geothermal wells as cement damage promotes migration of reactive fluids along and through the cement sheath, and reduces thermal isolation of the casing by the cement sheath. The resulting reduction in zonal isolation, enhanced casing corrosion, and elevated thermo-mechanical stresses may significantly reduce the lifetime of geothermal wells.
ABSTRACTIn recent years there has been an increased interest in drilling deeper geothermal wells to obtain more energy output per well with the corresponding higher temperature and pressure and increased corrosiveness of the geothermal environment. To explore the potential of the high alloy austenitic stainless steel UNS S31254 in future deep geothermal wells corrosion testing was done in simulated geothermal environment at 180°C and 350°C with a pressure of 10 bar. The simulated environment was composed of steam with H2S, HCl and CO2 gases, with a pH of 3 upon condensation. The testing was done in a flow through reactor for 1 and 3 week exposures. The stainless steel UNS S31254 performed well at 180°C with negligible corrosion rates both for the 1 and 3 week tests and no localized corrosion damage detected. After the testing at 350°C localized corrosion and substantial amount of NaCl crystals were observed on the surface of the samples. Microstructural and chemical composition analysis revealed large cracks in the cross-section of the sample most likely due to chloride induced stress corrosion cracking. The measured corrosion rate for the 1 and 3 week test was 0.024 mm/year and 0.24 mm/year respectively.INTRODUCTIONMaterials used in high temperature geothermal steam can be subjected to corrosion due to the chemical composition of the geothermal fluid. Geothermal fluids contain corrosive substances such as the dissolved gases hydrogen sulfide (H2S) and carbon dioxide (CO2), and chloride ions (Cl-)1-5. The source of chloride ions (Cl-) can be from volatile chloride transported as hydrochloric acid (HCl) in the gas phase from the volcanic system or from salt brine in geothermal areas close to the sea. If localized enrichment of hydrochloric (HCl) acid occurs e.g. due to condensation and/or re-boiling it will cause severe corrosion of materials in the systems6-7. H2S in wet environment, such as in geothermal environment, can also cause severe corrosion damage in materials exposed to the environment, including hydrogen induced cracking (HIC), stress corrosion cracking (SCC) and sulfide stress cracking (SSC)8-14.