No abstract

In this work, geochemical modelling using PhreeqC was carried out to evaluate the effects of geochemical reactions on the performance of underground hydrogen storage (UHS). Equilibrium, exchange, and mineral reactions were considered in the model. Moreover, reaction kinetics were considered to evaluate the geochemical effect on underground hydrogen storage over an extended period of 30 years. The developed model was first validated against experimental data adopted from the published literature by comparing the modelling and literature values of H2 and CO2 solubility in water at varying conditions. Furthermore, the effects of pressure, temperature, salinity, and CO2% on the H2 and CO2 inventory and rock properties in a typical sandstone reservoir were evaluated over 30 years. Results show that H2 loss over 30 years is negligible (maximum 2%) through the studied range of conditions. The relative loss of CO2 is much more pronounced compared to H2 gas, with losses of up to 72%. Therefore, the role of CO2 as a cushion gas will be affected by the CO2 gas losses as time passes. Hence, remedial CO2 gas injections should be considered to maintain the reservoir pressure throughout the injection and withdrawal processes. Moreover, the relative volume of CO2 increases with the increase in temperature and decrease in pressure. Furthermore, the reservoir rock properties, porosity, and permeability, are affected by the underground hydrogen storage process and, more specifically, by the presence of CO2 gas. CO2 dissolves carbonate minerals inside the reservoir rock, causing an increase in the rock’s porosity and permeability. Consequently, the rock’s gas storage capacity and flow properties are enhanced.

Scale deposition in oil and gas wells is still a major issue in the oil and gas industry as it reduces hydrocarbon production, restricts well access to production logging tools and, in addition, causes safety issues due to blocking and ineffective operation of chokes and valves. Scale is predominantly controlled with chemical scale inhibitors and the most common methods to control scale deposition are through continuous injection and scale squeeze treatments although solid inhibitors can be deployed in ratholes, hydraulic fractures and gravel packs. Non-chemical methods can also be applied and are becoming more common over the last few years especially for calcium carbonate control.Scale management is clearly still a very important factor for the good health of existing oil and gas wells and the trend towards net zero will only increase this reliance as the need for maximum production from existing assets becomes more pertinent compared to the alternative of developing new fields which will be more carbon intensive.Existing scale management strategies will also have a CO2 footprint and scale control methods will be reviewed to become more aware of this and to highlight how certain areas of scale management can become more effective and adapt to the changing needs of the energy industry such as the increasing use of enhanced oil recovery (EOR) in both conventional and unconventional fields.The review will include several areas of scale management including scale prediction risk, chemical and non-chemical treatments, scale inhibitor chemistry from renewable sources, monitoring techniques coupled with improved data processing techniques and automation.The drive towards net zero has also instigated the development of alternative energy sources to fossil fuels which have resulted in a major focus on projects in geothermal energy and increased the potential for carbon capture, utilisation and storage (CCUS) projects where CO2 captured from heavy industry is transported to site and injected into geological reservoirs for storage and/or enhanced oil recovery.Scale control will be important to both geothermal and CCUS projects and this paper will highlight examples including scale control in geothermal wells with options for treatment and desirable chemical properties and carbonate scale control in CO2Water Alternating Gas (WAG) injection whilst also demonstrating CO2 storage and enhanced oil recovery (CCUS). In addition, the potential for halite deposition and carbonate mineral dissolution and its impact on rock mechanical integrity during CO2 injection into hyper saline aquifers and depleted oil and gas reservoirs will be discussed.

Chevron and its Partners are facing several challenges in the North Atlantic Margin exploration and development. These challenges affect drilling design and operations, which should take in account several important factors occurring concurrently in this area: deepwater conditions;complex lithological sequence and target imaging uncertainty;geomechanical conditions. Hole section design is strongly affected by the uncertainty of the subsurface data, in particular the seismic data, where the presence of thick basalt flows, as strong reflectors, induce relatively poor seismic imaging of intra–basalt or sub–basalt drilling targets. This issue is mitigated with contingency plans for final hole section size and casing string setting depths. The complex lithological sequence, geomechanical conditions and lithological uncertainty also affect drilling fluid design and bit/bottom hole assembly (BHA) selection. The consideration of some of these factors had the outcome of using thixotropic muds to counter serious lost circulation events. A further successful outcome was the design and implemention of riserless drilling techniques, a first for Chevron Upstream Europe and Halliburton Baroid UK, to counter the threat of shallow water flows in the top hole sections. The paper demonstrates how a multi – disciplinary approach in both drilling design and operations is beneficial to successful drilling optimization in the North Atlantic Margin, a geographically and geologically challenging area.

Lithologies under deepwater conditions usually show relatively reduced effective stress, due to the reduced lithostatic column. This translates into relatively narrow mud weight windows, driven mainly by shear failure or pore pressure in overpressured conditions, and by minimum horizontal stress gradients. Drilling operations should consider wellbore collapse, kick and losses as the primary geomechanics-related drilling hazards. These should be investigated and predicted during well planning, and should also be appropriately monitored during drilling, especially when an appraisal campaign will require highly deviated wells. Real-time geomechanics is defined as a workflow that takes into consideration mud weight window planning, identification of geomechanics-related drilling hazards and possible mitigation actions, and, while drilling, operations monitoring by real-time data acquisition and interpretation, drilling occurrences detection, drilling practices revision, and the real-time update of mud weight window for further drilling. The authors present the case study of a drilling campaign in Chevron operated Rosebank Lochnagar Discovery, deepwater West Shetland, in almost 3,700-ft water depth. This campaign had the goal of proving the development concept of drilling horizontally in a field where the previous maximum inclination was only 35 degrees. The planning phase consisted of mud window modeling using a mechanical earth model from offset wells. Potential drilling hazards were then identified and synthesised using a Drilling Roadmap as a drillling planning and management tool. The monitoring phase consisted of real-time detection, from analysis of logging-while-drilling and wireline data, of drilling hazards typical in the area, such as cavings, losses, and packoffs. Data interpretation required a multidisciplinary team of geologists, petrophysicists, geomechanics engineers, and drilling engineers. The application of real-time geomechanics allowed an improvement in operations, safe drilling practices, and refined calibration of the 1D geomechanical model for further drilling campaigns.