Oleksandr Burachok

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 paper evaluates application of CO₂ injection for the control of water encroachment from the aquifer into gascondensate reservoir under active natural water drive. The results of numerical simulations indicated that injection of CO₂ at the initial gas-water contact (GWC) level reduces the influx of water into gas-bearing zone and stabilizes the operation of production wells for a longer period. The optimum number of injection wells that leads to the maximum estimated ultimate recovery (EUR) factor was derived based on statistical analysis of the results. The maximum number of injection wells at the moment of CO₂ break-through into production wells for homogeneous reservoir is equal to 6.41 (6) and for heterogeneous – 7.74 (8) wells. Study results indicated that with the increase of reservoir heterogeneity, denser injection well pattern is needed for the efficient blockage of aquifer water influx in comparison to homogeneous one with the same conditions. Gas EUR factor for the maximum number of injection wells in homogenous model is equal 64.05% and in heterogeneous – 55.56%. Base depletion case the EURs are 51.72% and 49.44%, respectively. The study results showed the technological efficiency of CO₂ injection into the producing reservoir at initial GWC for the reduction of water influx and improvement of ultimate hydrocarbon recovery.

CO2 emissions are considered to be the main contributor to global warming and climate change. One of the ways reducing the emissions to atmosphere is a proper capture and further geological storage of the carbon dioxide. In the oil industry, CO2 is used as one of the injection agents to displace oil and enhance its recovery. Due to the low multi-contact miscibility pressure between CO2 and hydrocarbons, fully miscible condition is quickly reached, leading to efficient displacement and high recovery factors. The utilization of the depleted gas fields for CO2 storage, however, is considered as the option that is more expensive compared to oil field, since the enhanced recovery of gas with CO2 is not effective. For this reason, our study considers the potential use of CO2 EOR in depleted gas-condensate fields. This potential is evaluated by performing numerical simulations for the typical-size gascondensate reservoirs with no active aquifer, in order to estimate both the storage efficiency and the additional oil recovery from condensed C5+ hydrocarbon fractions, that otherwise will be never recovered and lost in the reservoir. Obtained results indicate significant potential for CO2 storage and additional condensate recovery from the typical gas-condensate field of Eastern Ukraine.

The majority of the Ukrainian gas condensate fields are in the final stage of development. The high level of reservoir energy depletion has caused significant in situ losses of condensed hydrocarbons. Improving and increasing hydrocarbon production is of great importance to the energy independence of Ukraine. In this paper, a review of the pilot and commercial enhanced gas and condensate recovery (EGR) projects was performed, based on published papers and literature sources, in order to identify those projects which could potentially be applied to the reservoir conditions of Ukrainian gas condensate fields. The EGR methods included the injection of dry gas (methane), hydrocarbon solvents (gas enriched with C2–C4 components), or nitrogen and carbon dioxide. The most commonly used and proven method is dry gas injection, which can be applied at any stage of the field’s development. Dry gas and intra-well cycling was done on five Ukrainian reservoirs, but because of the need to block significant volumes of sales gas they are not being considered for commercial application. Nitrogen has a number of significant advantages, but the fact that it increases the dew point pressure makes it applicable only at the early stage, when the reservoir pressure is above or near the dew point. Carbon dioxide is actively used for enhanced oil recovery (EOR) or for geological storage in depleted gas reservoirs. In light of the growing need to reduce carbon footprints, CO2 capture and sequestration is becoming very favourable, especially due to the low multi-contact miscibility pressure, the high density under reservoir conditions, and the good miscibility with formation water. All of these factors make it a good candidate for depleted gas condensate reservoirs.

The problems of gas-condensate PVT-models (Pressure Volume Temperature, PVT) creation under limited input information were analyzed. Traditional fluid phase behavior characterization approach relies on creation of the equation of state (EOS) based on initial composition of reservoir fluid and its future regression for critical parameters (pressure and temperature), binary interaction coefficients, acentric factors of residual “plus” fraction or pseudo-components. The adjustment is done until the moment when EOS is reproducing the results of laboratory experiments. Classic PVT experiments performed on gas-condensates and volatile oils are constant composition expansion (CCE), constant volume depletion (CVD) and separator tests. However, in the case of most Ukrainian fields, discovered and explored in the last century, not only the reliable detailed initial fluid composition is not available, but phase behavior was studied with non-equilibrium method of so-called differential condensation, that does not allow their direct application for PVT models creation. Previously, the authors [1, 2] presented an alternative method for fluid characterization based on the fractional distillation test. At the same time, due to significant uncertainty in input data, particularly a) condensate production allocation; b) commingled production from multiple reservoirs with different C5+ yield; c) non-recorded change of separator conditions that affects liquid extraction and its density; d) technological production losses, issues of reproducing the condensate production during history matching of several models of Dniper-Donetsk Basin were faced. There was proposed and explained in detail an example of single-cell reservoir simulation model application concept for quality check of created PVT model for one of the fields with potential yield of 86 g/m3. The idea of the concept is based on the reproduction of material balance of gas-condensate reservoir through one conditional well controlled on a primary (gas) phase, that allows quick identification of changes into calculated gas-condensate yield curve, necessary for matching of condensate production. Implementation of these changes allows quick and precise full-field model calibration.

Досліджено умови за яких може бути досягнуто повне змішування азоту і вуглекислого газу із типовими газоконденсатними пластовими флюїдами із потенційним вмістом рідких вуглеводнів 100, 300 і 500 г/м3. За умови суттєвого виснаження пластової енергії і низьких пластових тисків, що характеризує кінцеві стадії розробки родовищ, повне змішування неможливо досягнути для жодного з цих невуглеводневих газів. Використання вуглекислого газу є більш сприятливим, оскільки на ранніх стадіях розробки, дозволяє отримати повне багатоконтактне змішування за тисків нижчих за початковий пластовий тиск. Проаналізовано ефективність нагнітання азоту і вуглекислого газу для витіснення конденсату, що випав у пласті, за умови максимального виснаження пластової енергії, коли пластовий тиск рівний тиску максимальної конденсації. Використання вуглекислого газу дозволяє збільшити коефіцієнт конденсатовилучення на 7%, у порівнянні з азотом для пластових систем із високим потенційним вмістом конденсату (500 г/м3).Ключові слова: нагнітання азоту, нагнітання вуглекислого газу, витіснення, змішування, конденсатовилучення.

Створення геолого-технологічних моделей є потрібною умовою для ухвалення оптимальних рішень щодо аналізу поточного стану, проєктування геолого-технологічних заходів і розрахунку прогнозних показників. У разі ізотермічного процесу для опису фазової поведінки та фазових перетворень використовують два основні способи: а) спрощена модель нелеткої нафти, так звана модель “чорної нафти” (ЧН), у якій кожна фаза – нафта, вода й газ представлена відповідним однойменним компонентом, а розв’язання рівнянь фільтрації ґрунтується на визначенні показників насичень і тисків за комірками чисельної моделі, а зміна властивостей пластових флюїдів задається в табличному вигляді як функція тиску; б) композиційна модель, у якій за допомогою рівняння стану фазова рівновага розраховується для вуглеводневих і невуглеводневих компонентів, а в процесі фільтраційних розрахунків, окрім насичень і тисків, нафтогазова суміш приводиться до фазової рівноваги і розраховується матеріальний баланс щодо кожного компонента в газовій і рідкій фазах. Для врахування леткості компонентів класичну модель ЧН удосконалено способом уведення газовмісту й кількості випаровуваної рідини, що дає змогу застосовувати її для більшості нафтогазових покладів, далеких від критичного стану, і в яких фазові перетворення в пласті не є такими істотними. Також через меншу кількість змінних, їхній чисельний розрахунок є простішим і набагато швидшим. Однак, зважаючи на важливість та актуальність проблеми збільшення видобутку українського газу та оптимізації розроблення газоконденсатних родовищ, постає питання можливості використання спрощеного описування поведінки фазових перетворень у газоконденсатних родовищах за допомогою PVT-моделі ЧН, що працюють на виснаження й визначення межі її застосування залежно від потенційного вмісту рідких вуглеводнів. У роботі виконано порівняльне дослідження показників розробки умовного покладу для синтетично-згенерованих пластових сумішей із різним потенційним вмістом С5+, які представлено у вигляді графічних залежностей і таблиць. За результатами можна визначити межу застосування спрощеної PVT-моделі ЧН і потрібний момент переходу на композиційну модель для отримання точніших результатів розрахунків.