The UK - The Global Hydrogen Centre

2021 ◽  
Author(s):  
Kent Martin Paul Massey ◽  
Jakub Vrba ◽  
Scott Hamilton ◽  
James Patrick McAreavey ◽  
Caragh Jane McWhirr ◽  
...  
Keyword(s):  
Hydrogen Production ◽  
Oil Recovery ◽  
Co2 Storage ◽  
Oil Fields ◽  
Technology Readiness ◽  
Perceived Risks ◽  
Corrosion Mechanisms ◽  
Carbon Dioxide Co2 ◽  
The Uk ◽  
Commercial Landscape

Abstract The paper proposes that the UK should be the global centre of hydrogen production and explores why and how this ambition could be achieved. The paper focuses on what government and industry need to do to realise this dream. We explain the technology, commerciality and legislation required in order to raise ambitions and create a sense of urgency within the hydrogen community. The paper justifies this bold statement, highlighting the fundamentals that the UK enjoys and compares these against other rival global centres, by considering the existing infrastructure whilst explaining the merits of the UKs diverse gas supply chain. The paper also explores and debunks technology readiness and perceived risks associated with hydrogen production. The paper concludes that the UK should adopt a bolder ambition for hydrogen, and suggests how the UK can move forward faster with recommendations for new commercial frameworks. The paper also demonstrates that the current perceived risks linked with blue hydrogen development, both technological and subsurface, are overstated. The paper sets out a commercial landscape that would enable rapid hydrogen development. The paper focuses on blue hydrogen production infrastructure, setting a timeframe of achievability whilst allowing for demand side influences. The paper also considers how to future-proof hydrogen infrastructure to facilitate green hydrogen co-production. The paper highlights the possible errors of decommissioning depleted oil fields where carbon dioxide (CO2) storage could be used to extend the life of the facilities, with possible enhanced oil recovery as an upside. The paper discusses how the liabilities currently hindering integrated hydrogen developments are more theoretical than real, by consideration of minimised leak paths and corrosion mechanisms. The paper also explains why these liabilities should ultimately be underwritten by government institutions.

A Laboratory and Numerical-Simulation Study of Co-Optimizing CO2 Storage and CO2 Enhanced Oil Recovery

SPE Journal ◽  
2015 ◽  
Vol 20 (06) ◽  
pp. 1227-1237 ◽  
Author(s):  
Fatemeh Kamali ◽  
Furqan Hussain ◽  
Yildiray Cinar
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Co2 Storage ◽  
Immiscible Displacement ◽  
Sandstone Sample ◽  
Miscible Displacements ◽  
Gravity Effects ◽  
Optimization Function ◽  
Carbon Dioxide Co2 ◽  
And Storage

Summary This paper presents experimental observations that delineate co-optimization of carbon dioxide (CO2) enhanced oil recovery (EOR) and storage. Pure supercritical CO2 is injected into a homogeneous outcrop sandstone sample saturated with oil and immobile water under various miscibility conditions. A mixture of hexane and decane is used for the oil phase. Experiments are run at 70°C and three different pressures (1,300, 1,700, and 2,100 psi). Each pressure is determined by use of a pressure/volume/temperature simulator to create immiscible, near-miscible, and miscible displacements. Oil recovery, differential pressure, and compositions are recorded during experiments. A co-optimization function for CO2 storage and incremental oil is defined and calculated using the measured data for each experiment. A compositional reservoir simulator is then used to examine gravity effects on displacements and to derive relative permeabilities. Experimental observations demonstrate that almost similar oil recovery is achieved during miscible and near-miscible displacements whereas approximately 18% less recovery is recorded in the immiscible displacement. More heavy component (decane) is recovered in the miscible and near-miscible displacements than in the immiscible displacement. The co-optimization function suggests that the near-miscible displacement yields the highest CO2-storage efficiency and displays the best performance for coupling CO2 EOR and storage. Numerical simulations show that, even on the laboratory scale, there are significant gravity effects in the near-miscible and miscible displacements. It is revealed that the near-miscible and miscible recoveries depend strongly on the endpoint effective CO2 permeability.

A Laboratory Study of Coinjection of Water and CO2 to Improve Oil Recovery and CO2 Storage: Effect of Fraction of CO2 Injected

SPE Journal ◽  
2020 ◽  
pp. 1-9
Author(s):  
Emmanuel Ajoma ◽  
Thanarat Sungkachart ◽  
Saria ◽  
Hang Yin ◽  
Furqan Le-Hussain
Keyword(s):  
Oil Recovery ◽  
Laboratory Experiments ◽  
Water Pressure ◽  
Co2 Storage ◽  
Water Injection ◽  
Molar Fraction ◽  
Co2 Injection ◽  
The Core ◽  
Carbon Dioxide Co2 ◽  
Water Saturated

Summary To determine the effect on oil recovery and carbon dioxide (CO2) storage, laboratory experiments are run with various fractions of CO2 injected (FCI): pure CO2 injection (FCI = 1), water-saturated CO2 (wsCO2) injection (FCI = 0.993), simultaneous water and gas (SWAG) (CO2) injection (FCI = 0.75), carbonated water injection (CWI) (FCI = 0.007), and water injection (FCI = 0). All experiments are performed on Bentheimer sandstone cores at 70°C and 11.7 MPa (1,700 psia). The oil phase is composed of 65% hexane and 35% decane by molar fraction. Before any fluid is injected, the core is filled with oil and irreducible water. Pressure difference across the core and production rate of gas are measured during the experiment. The collected produced fluids are analyzed in a gas chromatograph to determine their composition. Cumulative oil recovery after injection is found to be 78 to 83% for wsCO2, 78% for SWAG, 74% for pure CO2, 53% for CWI, and 35% for water. Net CO2 stored is also found to be the highest for wsCO2 (59 to 65% of the pore volume), followed by that for CO2 injection (56%) and that for SWAG (42%). These results suggest that wsCO2 injection might outperform pure CO2 injection at both oil recovery and net CO2stored.

scholarly journals CO2 storage in depleted oil fields: The worldwide potential for carbon dioxide enhanced oil recovery

2011 ◽  
Vol 4 ◽  
pp. 2162-2169 ◽  
Author(s):  
Michael Godec ◽  
Vello Kuuskraa ◽  
Tyler Van Leeuwen ◽  
L. Stephen Melzer ◽  
Neil Wildgust
Keyword(s):  
Carbon Dioxide ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Co2 Storage ◽  
Oil Fields

A revised assessment of the CO2 storage capacity and enhanced oil recovery potential in the major oil fields of Ohio

2017 ◽  
Vol 24 (1) ◽  
pp. 1-13 ◽  
Author(s):  
Jared Hawkins ◽  
Srikanta Mishra ◽  
Ryan Stowe ◽  
Kishan Makwana ◽  
Joel Main
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Storage Capacity ◽  
Co2 Storage ◽  
Oil Fields ◽  
Recovery Potential

scholarly journals Best Practice for Transitioning from Carbon Dioxide (CO2) Enhanced Oil Recovery EOR to CO2 Storage

2017 ◽  
Vol 114 ◽  
pp. 6950-6956 ◽  
Author(s):  
Ken Allinson ◽  
Dan Burt ◽  
Lisa Campbell ◽  
Lisa Constable ◽  
Mark Crombie ◽  
...  
Keyword(s):  
Carbon Dioxide ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Best Practice ◽  
Co2 Storage ◽  
Carbon Dioxide Co2

scholarly journals Sequential Injection of Carbonated Water: A Possible Process for Coupling CO2 Enhanced Oil Recovery and Storage

2020 ◽  
Vol 9 (3) ◽  
pp. 369-376
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Co2 Storage ◽  
Water Injection ◽  
Water Flooding ◽  
Core Flooding ◽  
Displacement Efficiency ◽  
Low Salinity ◽  
Carbonated Water ◽  
Carbon Dioxide Co2

Low salinity and carbonated water flooding have been investigated as possible techniques of improved/enhanced oil recovery. Carbonated water injection consists of dissolving carbon dioxide CO2 in water prior to injection and could be considered as a way to store greenhouse gas safely. Low salinity water flooding is a process of diluting high salinity injection water to a very low level of salinity. In this project, the effect of combining the two techniques in a sequential flooding was studied. The primary aim of this study is to optimize the oil recovery and evaluate CO2 storage during this process, employing low permeability carbonate cores and different sequential carbonated and non-carbonated brines flooding. Formation brine, seawater, low salinity carbonated and non-carbonated were used in this work. Core samples grouped as composite cores with similar over all reservoir permeability. Different sequences of brines were employed to determine the optimum system. The experiment's result showed that carbonated water performs better than the noncarbonated brines. A new technique for estimate CO2 retention based on the displacement efficiency of the carbonated water flooding system is presented. The interfacial tension, contact angle measurements results indicated that wettability is the dominant mechanism of the studied systems. A sequential composite core flooding consists of carbonated low salinity followed by low salinity and seawater injection (CLSW- LSW-SW) is the optimum flooding system among the studied systems. Technically, CLSW flooding displayed an excellent incremental displacement efficiency ∆DE of 21.4% and CSW exhibited the best CO2 retention per incremental ∆Np.

Experimental and Modeling Study of Salt Precipitation During Injection of CO2 Contaminated With H2S Into Depleted Gas Fields in the Northeast of the Netherlands

SPE Journal ◽  
2014 ◽  
Vol 19 (06) ◽  
pp. 1058-1068 ◽  
Author(s):  
P.. Bolourinejad ◽  
R.. Herber
Keyword(s):  
The Netherlands ◽  
Carbonic Acid ◽  
Co2 Storage ◽  
Mineral Dissolution ◽  
Co2 Injection ◽  
Salt Precipitation ◽  
Geological Time ◽  
Core Samples ◽  
Carbon Dioxide Co2 ◽  
Gas Fields

Summary Depleted gas fields are among the most probable candidates for subsurface storage of carbon dioxide (CO2). With proven reservoir and qualified seal, these fields have retained gas over geological time scales. However, unlike methane, injection of CO2 changes the pH of the brine because of the formation of carbonic acid. Subsequent dissolution/precipitation of minerals changes the porosity/permeability of reservoir and caprock. Thus, for adequate, safe, and effective CO2 storage, the subsurface system needs to be fully understood. An important aspect for subsurface storage of CO2 is purity of this gas, which influences risk and cost of the process. To investigate the effects of CO2 plus impurities in a real case example, we have carried out medium-term (30-day) laboratory experiments (300 bar, 100°C) on reservoir and caprock core samples from gas fields in the northeast of the Netherlands. In addition, we attempted to determine the maximum allowable concentration of one of the possible impurities in the CO2 stream [hydrogen sulfide (H2S)] in these fields. The injected gases—CO2, CO2+100 ppm H2S, and CO2+5,000 ppm H2S—were reacting with core samples and brine (81 g/L Na+, 173 g/L Cl−, 22 g/L Ca2+, 23 g/L Mg2+, 1.5 g/L K+, and 0.2 g/L SO42−). Before and after the experiments, the core samples were analyzed by scanning electron microscope (SEM) and X-ray diffraction (XRD) for mineralogical variations. The permeability of the samples was also measured. After the experiments, dissolution of feldspars, carbonates, and kaolinite was observed as expected. In addition, we observed fresh precipitation of kaolinite. However, two significant results were obtained when adding H2S to the CO2 stream. First, we observed precipitation of sulfate minerals (anhydrite and pyrite). This differs from results after pure CO2 injection, where dissolution of anhydrite was dominant in the samples. Second, severe salt precipitation took place in the presence of H2S. This is mainly caused by the nucleation of anhydrite and pyrite, which enabled halite precipitation, and to a lesser degree by the higher solubility of H2S in water and higher water content of the gas phase in the presence of H2S. This was confirmed by the use of CMG-GEM (CMG 2011) modeling software. The precipitation of halite, anhydrite, and pyrite affects the permeability of the samples in different ways. After pure CO2 and CO2+100 ppm H2S injection, permeability of the reservoir samples increased by 10–30% and ≤3%, respectively. In caprock samples, permeability increased by a factor of 3–10 and 1.3, respectively. However, after addition of 5,000 ppm H2S, the permeability of all samples decreased significantly. In the case of CO2+100 ppm H2S, halite, anhydrite, and pyrite precipitation did balance mineral dissolution, causing minimal variation in the permeability of samples.

A Laboratory Investigation of the Effect of Ethanol-Treated Carbon Dioxide Injection on Oil Recovery and Carbon Dioxide Storage

SPE Journal ◽  
2021 ◽  
pp. 1-17
Author(s):  
Saira ◽  
Emmanuel Ajoma ◽  
Furqan Le-Hussain
Keyword(s):  
Carbon Dioxide ◽  
Oil Recovery ◽  
Carbon Capture ◽  
Molar Fraction ◽  
Co2 Injection ◽  
Carbon Dioxide Injection ◽  
Treated Carbon ◽  
Carbon Dioxide Co2 ◽  
And Storage ◽  
Experimental Runs

Summary Carbon dioxide (CO2) enhanced oil recovery is the most economical technique for carbon capture, usage, and storage. In depleted reservoirs, full or near-miscibility of injected CO2 with oil is difficult to achieve, and immiscible CO2 injection leaves a large volume of oil behind and limits available pore volume (PV) for storing CO2. In this paper, we present an experimental study to delineate the effect of ethanol-treated CO2 injection on oil recovery, net CO2 stored, and amount of ethanol left in the reservoir. We inject CO2 and ethanol-treated CO2 into Bentheimer Sandstone cores representing reservoirs. The oil phase consists of a mixture of 0.65 hexane and 0.35 decane (C6-C10 mixture) by molar fraction in one set of experimental runs, and pure decane (C10) in the other set of experimental runs. All experimental runs are conducted at constant temperature 70°C and various pressures to exhibit immiscibility (9.0 MPa for the C6-C10 mixture and 9.6 MPa for pure C10) or near-miscibility (11.7 MPa for the C6-C10 mixture and 12.1 MPa for pure C10). Pressure differences across the core, oil recovery, and compositions and rates of the produced fluids are recorded during the experimental runs. Ultimate oil recovery under immiscibility is found to be 9 to 15% greater using ethanol-treated CO2 injection than that using pure CO2 injection. Net CO2 stored for pure C10 under immiscibility is found to be 0.134 PV greater during ethanol-treated CO2 injection than during pure CO2 injection. For the C6-C10 mixture under immiscibility, both ethanol-treated CO2 injection and CO2 injection yield the same net CO2 stored. However, for the C6-C10 mixture under near-miscibility,ethanol-treated CO2 injection is found to yield 0.161 PV less net CO2 stored than does pure CO2 injection. These results suggest potential improvement in oil recovery and net CO2 stored using ethanol-treated CO2 injection instead of pure CO2 injection. If economically viable, ethanol-treated CO2 injection could be used as a carbon capture, usage, and storage method in low-pressure reservoirs, for which pure CO2 injection would be infeasible.

Understanding the Flow Dynamics of CO2 Plumes in the Subsurface

2021 ◽  
Author(s):  
Florence Letitia Bebb ◽  
Kate Clare Serena Evans ◽  
Jagannath Mukherjee ◽  
Bilal Saeed ◽  
Geovani Christopher
Keyword(s):  
Carbon Capture ◽  
Oil And Gas ◽  
Co2 Storage ◽  
Flow Dynamics ◽  
Hydrocarbon Exploration ◽  
Hydrocarbon Reservoir ◽  
Exploration And Production ◽  
And Migration ◽  
Carbon Dioxide Co2 ◽  
Hydrocarbon Exploration And Production

Abstract There are several significant differences between the behavior of injected CO2 and reservoired hydrocarbons in the subsurface. These fundamental differences greatly influence the modeling of CO2 plumes. Carbon capture, utilization, and storage (CCUS) is growing in importance in the exploration and production (E&P) regulatory environment with the Oil and Gas Climate Initiative (OGCI) making CCUS a priority. Companies need to prospect for storage sites and evaluate both the short-term risks and long-term fate of stored carbon dioxide (CO2). Understanding the physics governing fluid flow is important to both CO2 storage and hydrocarbon exploration and production. In the last decade, there has been much research into the movement and migration of CO2 in the subsurface. A better understanding of the flow dynamics of CO2 plumes in the subsurface has highlighted a number of significant differences in modeling CO2 storage sites compared with hydrocarbon reservoir simulations. These differences can greatly influence reliability when modeling CO2 storage sites.

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