Hakan Alkan

Depleted hydrocarbon reservoirs (DHRs), particularly depleted gas reservoirs (DGRs), are increasingly regarded as promising candidates for geologic carbon storage (GCS). However, their low abandonment pressure poses significant thermo-hydraulic challenges during the injection of cold, high-pressure CO₂. In such non-isothermal conditions, complex processes may occur, including Joule–Thomson (J-T) cooling, hydrate formation, salt precipitation, and thermal fracturing, all of which may affect storage performance. This study presents an integrated assessment of the impact of CO₂ injection into DGRs on the three key pillars of GCS: capacity, injectivity, and containment. The analysis integrates laboratory experiments conducted at our institute, simplified analytics and numerical simulations to assess the governing physical mechanisms. The findings indicate that the cold CO₂ injection can enhance effective storage capacity during the injection phase. This is attributed to the increase in fluid density and the delay in pressure buildup. However, the post-injection thermal equilibrium may result in pressure rebound. The CO₂ injectivity has been demonstrated to be significantly impacted by the near-wellbore thermal effects. While thermo-induced fracturing may enhance injectivity, it poses potential risks to wellbore and caprock integrity. The process of hydrate formation depends on the local temperature and petrophysical conditions, with dynamic factors further reducing the likelihood of pore plugging. Salt precipitation has been found to be less critical under typical DGR conditions with low initial water saturation, although having the potential to become significant in the presence of water influx and/or cyclic injection. The findings provide a technical basis for enhancing the engineering design, accelerating the certification process, and ensuring the safe operation of future GCS projects in DGRs.

In today’s industry, H₂ is mostly produced from fossil fuels such as natural gas (NG), oil, and coal through various processes. However, all these processes produce both carbon dioxide (CO₂) as well as H₂, making them questionable in terms of climate change mitigation efforts. In addition to efforts to increase the conversion efficiency of green H₂ technologies, work is also underway to make H₂ production from fossil fuels more environmentally friendly by reducing/avoiding CO₂ emissions. In this framework, these technologies are combined with geologic carbon storage. In a further step, the use of depleted hydrocarbon reservoirs for in situ H₂ production is being investigated, with the co-generated CO₂ remaining permanently in the reservoir. The objective of this paper is to provide a brief overview of the technologies that can be used to produce H₂ from depleted and depleting hydrocarbon reservoirs (DHRs) in various ways. We evaluate the required processes from a reservoir engineering perspective, highlighting their potential for H₂ generation and their technology readiness level (TRL) for applications. We also investigate the possibility of permanently storing the co-produced CO₂ in the reservoir as a means of mitigating emissions. In addition, we provide a preliminary cost analysis to compare these methods with conventional hydrogen production techniques, as well as an assessment of operational risks and associated cost estimates.

Integrity of wellbores and near wellbore processes are crucial issues in geological carbon storage (GCS) projects as they both define the confinement and injectivity of CO₂. For the proper confinement of CO₂, any flow of CO₂ along the wellbore trajectory must be prevented using engineered barriers. The effect of cyclic stimuli on wellbore integrity, especially in the context of GCS projects, has been given less attention. In this study, the effect of pressure- and temperature-cycling on two types of wellbore composites (i.e., casing-cement and cement-caprock) have been investigated experimentally in small- and large-scale laboratory setups. The experiments have been carried out by measuring the effective permeability of the composites under pressure and thermal cyclic conditions. Furthermore, the permeability of individual samples (API class G and HMR+ cement and caprock) was measured and compared to the permeability of the composites. The results indicate that the permeability of API class G cement when exposed to CO₂ is in the order of 10⁻²⁰ m² (10⁻⁵ mD) as a result of the chemical reaction between the cement and CO₂. In addition, the tightness of the composite cement–rock has been confirmed, while the permeability of the composite casing–cement falls within the acceptable range for tight cement and the CO₂ flow was identified to occur through or close to the interface casing–cement. Results from thermal cycling within the range −9 to 14 °C revealed no significant effect on the integrity of the bond casing–cement. In contrast, pressure cycling experiments showed that the effective pressure has a larger influence on the permeability. The potential creation of micro-cracks under pressure variations may require some time for complete closing. In conclusion, the pressure and temperature cycling from this study did not violate the integrity of the casing–cement composite sample as the permeability remained low and within the acceptable range for wellbore cement.

The formation of hydrogen sulfide (H₂S) in petroleum reservoirs by anaerobic microbial activity (through sulfate-reducing microorganisms, SRMs) is called biogenic souring of reservoirs and poses a risk in the petroleum industry as the compound is extremely toxic, flammable, and corrosive, causing devastating damage to reservoirs and associated surface facilities. In this paper, we present a workflow and the tools to assess biogenic souring from a pragmatic engineering perspective. The retention of H₂S in the reservoir due to the reactions with iron-bearing rock minerals (e.g., siderite) is shown in a theoretical approach here and supported with literature data. Cases are provided for two fields under secondary (waterflooding) and tertiary flooding with microbial enhanced oil recovery (MEOR). The use of the Monte Carlo method as a numerical modeling tool to incorporate uncertainties in the measured physical/chemical/biochemical data is demonstrated as well. A list of studies conducted with different chemicals alone or in combination with various biocides to mitigate biogenic souring provides an overview of potential inhibitors as well as possible applications. Furthermore, the results of static and dynamic inhibition tests using molybdate are presented in more detail due to its promising mitigation ability. Finally, a three-step workflow for the risk assessment of biogenic souring and its possible mitigation is presented and discussed.

The formation of hydrogen sulfide (H₂S) in petroleum reservoirs by anaerobic microbial activity is called biogenic souring of reservoirs and is a risk in the oil and gas industry as the compound is extremely toxic, flammable and corrosive. In this paper, we present a workflow and the tools to assess biogenic souring from a pragmatic engineering perspective. The retention of H₂S in the reservoir due to the reactions with iron-bearing rock minerals (e.g. siderite) is shown in a theoretical approach here and supported with literature data. Cases are given for two fields under secondary (waterflooding) and tertiary flooding with microbial enhanced oil recovery (MEOR). The use of the Monte Carlo method as a numerical modelling tool to incorporate uncertainties in the measured physical/chemical/ biochemical data is demonstrated as well. A list of studies conducted with different chemicals alone or in combination with various biocides to mitigate biogenic souring provides an overview of potential inhibitors as well as possible applications. Furthermore, the results of static and dynamic inhibition tests using molybdate are presented in more detail due to its promising mitigation ability. Finally, a three-step workflow for the risk assessment of biogenic souring and its possible mitigation is presented and discussed.