Bagheri, Mohammadreza (Research Centre for Fluid and Complex Systems, Coventry University) | Shariatipour, Seyed M. (Research Centre for Fluid and Complex Systems, Coventry University) | Ganjian, Eshmaiel (School of Energy, Construction and Environment, Built & Natural Environment Research Centre, Coventry University)
The fluid pressure, the stress due to the column of the cement in the annulus of oil and gas wells, and the radial pressure exerted on the cement sheath from the surrounding geological layers all affect the integrity of the cement sheath. This paper studies the impact of CO2-bearing fluids, coupled with the geomechanical alterations within the cement matrix on its integrity. These geochemical and geomechanical alterations within the cement matrix have been coupled to determine the cement lifespan. Two main scenarios including radial cracking and radial compaction, were assumed in order to investigate the behaviour of the cement matrix exposed to CO2-bearing fluids over long periods. If the radial pressure from the surrounding rocks on the cement matrix overcomes the strength of the degraded layers within the cement matrix, cement failure can be postponed, while on the other hand, high vertical stress on the cement matrix in the absence of a proper radial pressure can lead to a reduction in the cement lifespan. The radial cracking process generates local areas of high permeability around the outer face of the cement sheath. Our simulation results show at the shallower depths the cement matrices resist CO2-bearing fluids more and this delays exponentially the travel time of CO2-bearing fluids towards the Earth's surface. This is based on the evolution of CO2 gas from the aqueous phase due to the reduction in the fluid pressure at shallower depths, and consumption of CO2 in the reactions which occur at the deeper locations.
Boersheim, Erik Clemens (Clausthal University of Technology) | Reitenbach, Victor (Clausthal University of Technology) | Albrecht, Daniel (Clausthal University of Technology) | Pudlo, Dieter (FSU Jena) | Ganzer, Leonhard (Clausthal University of Technology)
Hydrogen is portrayed as the fuel of the future. The storage of hydrogen in porous underground gas storages is a promising solution for large-scale energy storage in Germany. In theory, excess energy sourced from renewable sources would be converted to hydrogen and subsequently stored in underground porous media. This solution provides cost effective solutions whilst providing large capacities in comparison to other energy storage types, however hydrogen interactions in underground gas storage sites (UGS) is a perplexing topic due to its foreign nature and therefore its behavior in the subsurface could be unpredictable.
The implementation of autoclaves to recreate UGS with added hydrogen is a novel approach to investigate potential integrity issues that may arise during its lifetime. Where autoclaves can simulate conditions similar to UGS to analyze potential changes in the subsurface. The principal idea of autoclaves are to house samples which are exposed to pressures and temperatures equivalent that of typical Underground Gas Storages (max 200 bar, 120°C), allowing the recreation of any reservoir environment.
The Primary objective is to investigate interactions between subsurface materials combined with reservoir rock and hydrogen. Aforementioned interactions can be interpreted through the analysis of mineralogical, petrophysical, hydrochemical changes to ascertain information regarding to the productivity of the UGS, for examples reviewing changes in permeability and porosity.
Furthermore, the application of autoclaves can help to estimate the magnitude of hydrogen damage in subsurface equipment by providing insight into identifying key materials necessary to design a system preventing hydrogen damage to the subsurface; Supplementary implementation of conventional component inspection of mechanical properties of steels and cements through tensile strength testing and unconfined compressive strength testing, respectively, enable the extent of hydrogen damage inspection in UGS with added hydrogen. Predominantly API grade steels and API Grade G cement where used for this investigation. Preliminary autoclave experimentation results show that hydrogen can alter the characteristics of UGS, where API steels have shown to experience mild hydrogen damage and reservoir rock and API cement G samples have alterations in their chemical and physical characteristics.
Autoclaves provide flexible choice in testing parameters and can be used to recreate any UGS with any gas mixtures, allowing for limitless testing possibilities to test for potential integrity issues in porous UGS containing hydrogen.
The technical and economic successes of deep geothermal development rely on reducing drilling and completion risks. In the closely related oil and gas activities, the risk taken by the investors is balanced by the high reward that successful projects achieve by immensely offsetting the losses of the failed wellbores. Geothermal projects experience similar risks, however, the potential reward is limited by the competition with other energy sources, in a heavily regulated market. The economic acceptability of geothermal power generation requires low risk drilling and completion technologies that would work under many different geological conditions.
When wells are drilled into a petro-thermal formation, sometimes referred to as hot dry rock (HDR), there is normally no clear circulation path between these wells and when this path exists, the transmissivity is so low that no economical project is possible. Enhanced geothermal systems (EGS), in these circumstances is closer to reservoir creation than to conventional reservoir stimulation. Therefore, developing technologies that achieve the designed EGS size and transmissivity is vital to deep geothermal development.
The EGS becomes a viable proposition, when enough rock surface can be contacted by the geothermal fluid, and when the flow path runs smoothly through a sufficient rock volume to minimize the energy depletion and have the project running over a long period, compatible with a positive net present value (NPV). To that end, the well design and its completion system have to be engineered to maximize the chances of properly creating the EGS. In this paper, lessons learnt from past geothermal experience are reviewed and analysed to propose a multi-stage system as a mean of improving geothermal wells completion reliability. Current oil and gas (namely "unconventional") completion technologies related to multi-stage stimulation have been reviewed and different options are discussed in the scope of a deep geothermal hot dry rock project. While previous works conclude that technologies developed for oil and gas are readily available and applicable to deep geothermal projects and EGS (Gradl, 2018), this study shows that shortcomings exist and that further developments are necessary to reliably and economically complete EGS projects. The necessary tests before running different parts is also discussed. Other options for reservoir creation are debated with their potential benefits and associated risks. The developments that could make them work in an EGS project are discussed.
Well RXY is located in Cairn’s Ravva offshore field in the Krishna-Godavari Basin in India. One goal for the field was significant crude production by means of a secondary reservoir section. This paper compares the results of gas identification and lithology identification using pulsed-neutron spectroscopy in openhole and casedhole environments. Acquiring data from an abandoned subsea well has been done before, but never quite like this. As I read through the abstracts and papers that have been presented in the past year, I notice several key themes: verification of cement placement, development of new materials as a barrier, development of new additives to improve the cement barrier, and enhancement of existing techniques.
Tangen, Geir Ivan (Lundin Norway AS) | Smaaskjaer, Geir (Lundin Norway AS) | Bergseth, Einar (Lundin Norway AS) | Clark, Andy (Lundin Norway AS) | Fossli, Børre (Enhanced Drilling AS) | Claudey, Eric (Enhanced Drilling AS) | Qiang, Zhizhuang (Enhanced Drilling AS)
In 2015, while coring in the carbonate reservoir in the second appraisal well on an oil and gas discovery in the Barents Sea (386 m water depth), the drill string fell 2 meters and a total mud loss was experienced leading to a well control incident. As a result, since 2016, the operator has introduced and used the Controlled Mud Level (CML) system. To date this system has been used on seven wells including two further appraisal wells on the same field and five exploration wells in the area.
In 2017 it was decided to drill a horizontal well in the same carbonate reservoir and to perform an extended production test in close proximity to the original loss well. Since it is not possible to predict where large voids (karsts) and natural fractures could be encountered, contingency to handle high losses, had to be implemented for the horizontal well. During the well planning, further risk reducing measures were implemented, including the use of wired drill pipe to improve the management of the wellbore pressure profile. This paper describes the planning processes leading up to the operation and the highlights of the operation itself together with the lessons learned. It elaborates on how wired pipe, used in combination with the CML system, added value to the operation. It shows how it was possible to drill the reservoir section with a low overbalance while managing severe losses associated with open karsts and natural fractures and still maintaining the fluid barrier. Despite the severe losses encountered it was possible to safely drill and complete the well without any well control event by use of the CML system.
Cement sheath is a critical barrier for maintaining well integrity. Formation of micro-annulus due to volume shrinkage and/or pressure/temperature changes is the major challenge in achieving good hydraulic seal. Expansion of cement after the placement is a promising solution to this problem. Expanding cement can potentially close micro-annulus and further achieve pre-stress condition because of the confinement. Primary aim of this paper is to investigate mechanical integrity of different pre-stressed cement system under loading condition.
To achieve the objectives, finite element modelling approach was employed. Three dimensional computer models consisting of liner, cement sheath, and casing were developed. Pre-stress condition was generated by modelling contact interference at the cement-casing interface. Three cement (ductile, moderately ductile, and brittle) were considered for simulation cases. Wellbore and annulus pressure were applied. Resultant, radial, hoop, and maximum shear stresses were investigated at the cement-pipe interface to assess mechanical integrity. For comparison purpose, similar simulations were conducted using cement sheath without pre-stress and cement system representing uniform volume shrinkage and presence micro-annulus.
For constant wellbore pressure, the radial stresses observed in all three types of cement system were practically similar and decreased as pre-stress was increased. Hoop stress also reduced with increase in compressive pre-load. However, their absolute values were distinct for different cement types. These results indicate that cement system with compressive pre-load can notably reduce the risk of radial crack failure by providing compensatory compressive stress. However, on the contrary, the maximum shear stress developed at cement-pipe interface, increased because of pre-load. This can compromise the mechanical integrity by reducing the safety margin on shear failure. Thus, the selection of expansive cement should be made after carefully weighing reduced risk of radial failure/debonding against the increased risks of shear failure.
This paper provides novel information on expanding cement from the perspective of mechanical stresses and integrity. Modelling approach discussed in this work, can be used to estimate amount of pre-stress required for a selected cement system under anticipated wellbore loads.
Cement is a key element for successful drilling and completing of a well. From oil and gas wells to geothermal applications, cement is a major material ensuring zonal isolation. With an increase in global energy needs and an expected uptick in drilling and plugging and abandonment activities, evaluating and understanding cement properties is crucial, since these properties are used in various engineering designs and calculations. The objective of this paper is to present how Nuclear Magnetic Resonance (NMR) can be used to understand the cement hydration process and the development of key properties such as strength and porosity. NMR applications for cement include determination of porosity, water interactions, identification of hydration stages and C-S-H gel development with curing time. Since water is present in all cement slurries, NMR can potentially help to understand microstructural changes in cement during curing. Data from more than 600 cement specimens cured for more than a year are compiled. Standard cement properties such as UCS (unconfined compressive strength) are compared with NMR responses. In this paper, we document cement hydration and porosity changes through NMR measurements in samples with five different recipes. Our study also confirms a strong correlation between NMR response and cement strength.
Kumar, Abhineet (Cairn Oil & Gas, Vedanta Limited) | Prakash, Aditya (Cairn Oil & Gas, Vedanta Limited) | Singh, Alok (Cairn Oil & Gas, Vedanta Limited) | Bharati, Pradeep (Cairn Oil & Gas, Vedanta Limited) | Jayan, Binshu (Cairn Oil & Gas, Vedanta Limited) | Kothiyal, Manish (Cairn Oil & Gas, Vedanta Limited) | Patil, Bhushan (Cairn Oil & Gas, Vedanta Limited) | Sarma, Phanijyoti (Cairn Oil & Gas, Vedanta Limited)
An offshore drilling campaign comprising of four development wells was conducted to augment oil production from a field located off the western coast of India. All four wells were designed to be sidetracked from existing depleted wells of the field. Historically, preparing existing wells in the field for side-track took ~4 days/well of a drilling rig and associated spread cost. This paper presents a case- history of conducting side-track well preparatory activities by a rig-less well intervention spread leading to significant time and cost savings. This method was also the first instance of such an activity being conducted in an offshore environment in India.
Prior to actual side-track drilling from an existing well in a brown field, it is required to abandon the open zones in the existing well and prepare the well for casing window cutting for further drilling to a new sub-surface target. Typical preparation activities include multiple wireline runs to set/retrieve deep set and tubing hanger plugs, well killing, nipple-down X-mas tree, nipple-up BOP, wireline run to cut tubing, retrieval of existing completion and ultimately placement of cement plugs to abandon the parent wellbore. The routine approach in the organization for all previous offshore drilling campaigns was to utilize the offshore drilling rig for afore-mentioned well preparation activities. Substantial rig time was spent incurring the cost of entire rig spread for an average ~4 days/well equivalent to ~40% of total well completion time.
The paper elaborates on rig-less operations set-up consisting of Cementing and Wireline Units utilized to conduct well killing, placement of cement plugs, production tubing cutting and nippling down X-mas tree prior to the mobilization of the drilling rig at the platform. The only operation left for the drilling rig was to pull-out the existing completion string and then drilling operations could commence.
The execution of planned operations was flawless on three wells while one well posed technical limitation due to its high deviation. The rig less well preparation campaign was concluded incident free, ahead of schedule and within budget. This offline exercise prior to rig-move saved ~12 days of drilling campaign time which helped in cutting down on overall drilling campaign cost and also allowed the flexibility of adding more wells to the campaign within fair weather window.
While this was an effort to simplify operations and save costly drilling rig-time in a side-track drilling campaign by conducting some very critical operations offline, these methods can also be adopted for planning well abandonment and decommissioning activities in a mature field.
Primary cementing operations rank among the more important events that occur during a well's lifetime. The cement sheath plays a critical role in establishing and maintaining zonal isolation in the well, supporting the casing and preventing external casing corrosion.
For many years, the industry has employed strategies to promote optimal cement placement results. These strategies, collectively known in the industry as good cementing practices. Job execution is the key to insure success of the job based on the designed.
New technology that give us optimum execution evaluation (OEE) has been developed to enhance cement job execution by overlapping the design parameter over with the execution parameter real time. The OEE technology significantly improves cementing operations, enabling operators to monitor, control, and evaluate cement placement in real time. OEE combines job design data with acquisition data from both the rig and the cementing equipment to provide a more accurate representation of the job as it is being run.
In this paper, we present the process that we completed with detailed operational setup to allow us to monitor and record all parameters related to the cement job execution and the work flow implemented to be able to evaluate the cement job design and execution to achieve the required objectives. This study is also setting the basis to establish development of real time automated cementing advisory system.
Wellbore integrity is very critical in oil and gas industry and needs to be maintained through the entire cycle of well's life. The most important item for well integrity is to set cement between two casings or between casing and formation. A good cement job provides isolation and protection for the well and a poor cement job can have cracks and allows corrosive fluids to migrate through micro channels.
Downhole casing repair is a common workover operations worldwide, especially in wells that have been producing over number of years. It is very challenging to control corrosive fluid migration which slowly corrodes casing and tubing over time. An innovative epoxy resin formulations has been developed and tested in the field to repair casing leaks which is extremely easy to handle and very economical. A cost-effective workover program can be developed and implemented depending on the severity of the leak.
The improved approach of using innovative resin can be used by mixing with cement blends to repair major casing damage and can also be used as standalone application to fix minor leaks. The system maintains extremely good rheological properties even when mixed with cement. The system has ability to withstand high differential pressure and is also resistant to acid, salts, hydrocarbons and most importantly various corrosive liquids. The precise application is determined by measuring the injectivity of the well. In the low injectivity wells, only epoxy resin solution will be spotted and repair the damaged casing. In the high injectivity wells, the chemical will be mixed with cement and completely seal the damaged zone. The chemical will enhance the mechanical properties of the cement and will be more resilient to extreme down-hole condition.
The paper will emphasize the added value and potential of the method in restoring the casing integrity. The paper will also discuss the laboratory test reports and application which will highlight effective and economical outcome.