Reverse circulation cement placement is the technique when cement slurries are pumped down the annulus and up the casing, as opposed to conventional primary cementing where fluids are pumped down the casing. Reverse circulation can reduce bottom hole pressures compared to conventional cementing, making it particularly attractive for cementing zones where margins to the fracture pressure are small. Since the fluids are not mechanically separated in the annulus, density and viscosity hierarchies need to be carefully designed to minimize mixing and slurry contamination. We investigate the effect of variations in density and viscosity on the displacement efficiency by means of computational fluid dynamics to improve the design of a successful reverse circulation cementing operation.
The simulations are performed using an open-source computational fluid dynamics software, enabling a parameter study of the effect of flow rate, inclination, standoff and fluid parameters such as density and viscosity on the displacement process. We compare the reversed circulation displacement efficiency and the hydraulic pressure in the annulus to corresponding conventional primary cementing operations.
The displacement flows involve complex non-Newtonian viscosities in eccentric annuli, and the flow is typically fully three-dimensional. The efficiency and quality of the fluid-fluid displacement is governed by the hierarchy of fluid properties between the displaced and displacing fluids for both conventional and reverse circulation cementing. Furthermore, it is shown how flow rate and geometric constraints such as inclination and standoff affect the efficiency.
Previous work has focused primarily on hydraulic pressure and downhole temperature calculation. We investigate the effect of fluid hierarchies on cement contamination during reverse circulation cementing. The combination of fluid hierarchies and flow rate need to be carefully designed to avoid cement contamination while maintaining low bottom hole pressures during reverse circulation.
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.
Growing commercial activities in the High North increase the possibility of unwanted incidents. The vulnerability related to human safety and environment as well as a challenging context, call for a strengthening of the maritime preparedness system, cross-border and cross-institutional collaboration. In this paper, we look into the different stressors and risk factors of the sea regions in the High North. We elaborate on emergencies where integrated operations like mass evacuation is needed. We build upon in-depth studies of two cruise ship incidents close to the Spitsbergen Islands, and full-scale exercises in the Arctic region. We claim that coordination of such operations where several institutions and management levels are included demands significant integration and communication efforts. Implications for the training of key personnel responsible for coordinating such operations are discussed.
Emergency situations are often characterized by lack of overview and uncertainty about cause, consequences and suitable safety barriers. In areas like the High North, due to limited infrastructure and the scarcity of emergency capacities, a simple emergency situation can quickly turn into a crisis involving significant risk for people, nature and vulnerable societies. The turbulent weather conditions facing emergency actors, makes rescue and relief operations a challenging and time consuming task. In this paper, we examine how the emergency management has to be configured to overcome challenges related to large-scale emergencies with limited local infrastructure, long distances and harsh weather conditions in icy waters. In addition, we consider the limited availability of emergency support systems and the time delays caused by the geographical distances.
By examining the various emergency situations we reflect on suitable composition of the infrastructure, emergency groupings, and coordination mechanism.
Emergency Management and Emergency Response Pattern
High levels of uncertainty combined with a need for fast and reliable action are the main characteristic of emergencies (Kyng, Nielsen, and Kristensen 2006). Major incidents like shootouts and terror action, or cruise ship groundings with mass rescue operations (MRO) are categorized by lack of sufficient resources to meet the emergency situation. These situations are often chaotic and stressful with a large number of causalities, and a mix of SAR capacities. Thus, obtaining and maintaining an overview for such an incident become extremely hard for the coordinators and the different levels of command.
Since the devastating earthquake of 2010 in Haiti, significant efforts were devoted to estimating future seismic and tsunami hazard in Hispaniola. In 2013, the UNESCO commissioned initial modeling studies to assess tsunami hazard along the North shore of Hispaniola (NSOH), which is shared by the Republic of Haiti (RH) and the Dominican Republic (DR). This included detailed tsunami inundation for two selected sites, Cap Haitien in RH and Puerto Plata in DR. This work is reported here.
In similar work done for critical areas of the US east coast (under the auspice of the US National Tsunami Hazard Mitigation Program), the authors have modeled the most extreme far-field tsunami sources in the Atlantic Ocean basin. These included: (i) an hypothetical Mw 9 seismic event in the Puerto Rico Trench; (ii) a repeat of the historical 1755 Mw 9 earthquake in the Azores convergence zone; and (iii) a hypothetical 450 km3 flank collapse of the Cumbre Vieja Volcano (CVV) in the Canary Archipelago. Here, we perform tsunami hazard assessment along the NSOH for these 3 far-field sources, plus 2 additional near-field coseismic tsunami sources: (i) a Mw 8 earthquake in the western segments of the nearshore Septentrional fault, as a repeat of the 1842 event; and (ii) a Mw 8.7 earthquake occurring in selected segments of the North Hispaniola Thrust Fault (NHTF).
Based on each source parameters, the initial tsunami elevation is modeled and then propagated with FUNWAVE-TVD (a nonlinear and dispersive long wave Boussinesq model), in a series of increasingly fine resolution nested grids (from 1 arc-min to 200 m) based on a one-way coupling methodology. For the two selected sites, coastal inundation is computed with TELEMAC (a Nonlinear Shallow Water long wave model), in finer resolution (down to 30 m) unstructured nested grids. Although a number of earlier papers have dealt with each of the potential far-field tsunami sources, the modeling of their impact on the NSOH as well as that of the near-field sources, presented here as part of a comprehensive tsunami hazard assessment study, are novel.
We present an integrated analysis of laboratory-based thermally induced fracturing and results of numerical models to give insight to the role of thermal shock fracture on geothermal reservoir rocks. Thermal stimulation is a reservoir permeability enhancement technique applied to commercial geothermal reservoir rocks to enhance fluid injection capabilities for spent power plant working fluids. The process is well known to enhance permeability but the thermodynamic and physical constraints of the process are less certain. In an attempt to constrain the interaction and the ideal conditions that lead to permeability enhancement, experimental procedures were carried out to mimic the conditions that a reservoir rock would experience during a thermal stimulation using temperature differentials ranging from 50-300°C. Samples underwent such thermal gradients under controlled laboratory conditions and were characterized for the changes to permeability, porosity, ultrasonic velocities, dynamic elastic moduli and petrological changes. The thermal stimulation was simulated in a FLAC2D thermal numerical model to investigate the nature of the thermally induced changes in the sample. The development of this model also allows us to investigate the relationship between geological characteristics and the ability to thermally stimulate any type of rock. The results indicate that numerical thermal shocking experiments are corroborated by laboratory-based results. The implication of this study is that the refined numerical models present an insight to the conditions and constraints under which thermal stimulation can prove to enhance permeability that could not be gained through purely laboratory-based studies.
Thermal cracking of rocks is a process that can enhance permeability, reduce strength and have a significant effect on the competency of rocks in engineering applications. Thermal cracking as a result of induced temperature gradients in rock needs to be a consideration when rocks have undergone thermal stress in environments such as nuclear waste repositories, stone structures subjected to fires and geothermal reservoir rocks. Unlike the latter examples where thermal gradients can compromise structural integrity, geothermal reservoirs can benefit from thermal cracking as a permeability enhancement technique. The application of thermal stimulation to geothermal reservoirs has been shown to help improve the output and injection capacity of many geothermal wells worldwide (e.g. Axelsson and Thórhallsson, 2009; Grant et al., 2013) The process generally involves injection of water into wellbores that is cooler than the geothermal reservoir and through a combination of contraction and thermal cracking, permeability is enhanced. However, the processes that constrain successful stimulation are less well constrained and require both laboratory and numerical simulation to attempt to understand the underlying mechanisms.
Offshore oil and gas projects in the Arctic are to an increasing extent subject to global public opinion and scrutiny. Over the past decade the Arctic has turned into the World's back yard, where potential impacts can easily become a global topic for discussion. Looking from an industrial perspective to Arctic operations, it is thus of major importance to gain the support of local stakeholders counter balancing international tumult.
Gaining local support for developing offshore operations is dependent on a number of factors, including the benefits for local societies besides the taxes paid to a national government. Local support cannot be fooled, tricked or manipulated over a resisting population just as soft power is not empty propaganda. Not always the initiative to support local societies comes from the oil companies themselves. Often it is the regulation of a country making it mandatory for oil companies to exercise these efforts. These efforts could thus be seen as obligatory while they do not necessarily only cost money, but also increases local resilience which could lead to support for a company's operations. However, these longer term positive externalities are often hard to measure and quantify.
This manuscript will look at three case studies: the Faroese Islands, Iceland and Greenland. These three microstates have the aim to develop an oil & gas sector. Potential impacts of these developments are mostly felt locally, while the product will be mainly exported globally. For this reason the local societies are aiming to maximise their benefits and use a number of policy instruments to ensure this will happen. This manuscript will examine the measures that are incorporated into the Faroese, Greenlandic and Icelandic policies to stimulate local competence development via higher and vocational education. Furthermore it will try to illustrate how supporting and funding local competence development could contribute to increasing the resilience of local societies in the Arctic and obtaining a social license to operate.