Welcome to the Weekly Data Dive with bMark™ Software! 📊
Dive into the dynamic world of energy trends and environmental insights as we unravel the latest findings from our cutting-edge datasets. Every week, we bring you a captivating journey through the realms of recovery factors, carbon sequestration potential sites, oil recovery dynamics, and beyond.
Our #Trendoftheweek this week looks at comparing the spatial distribution of Ports and large CO2 emission sites in western Europe.
As industrial emitters look to CCS to decarbonise their operations, a critical aspect of this planning is the transportation infrastructure which can link CO2 sources to storage sites.
Several CCS projects plan to transport CO2 by ship. Where are the ports that can meet this requirement? Are there clusters of emitters that can network infrastructure to minimise costs?
To enable teams to answer these questions, the team here at Belltree have developed a global Ports database of over 3600 ports. Built on top of our other industry-leading datasets this forms another part of the source to sink screening workflow in bMark™.
Contact us today to see how bMark™ can empower your workflows.
You might expect there to be many differences in how oil and gas assets are developed and managed across the world, based on influences like drilling costs, drive mechanism preferences and energy requirements. But what does the data show?
By taking two highly productive regions – the North Sea (NS) and the Gulf of Mexico (GoM) – we can start to analyse if any systematic trends are apparent. We are visualising, on this plot, average profiles generated based on different filters applied in bMark™. Normalised parameters are used on both the x and y axis to account for variation in assets such as size and age.
We can see that the larger fields (>300MMstb) behave very similarly in both regions with plateau offtake rates around 8-9% of the EURo and a steady decline from around 40% EURo.
When we add back in the smaller fields in both regions, the story is very different. The GoM average remains similar to the previously identified trends, implying that development is consistent regardless of field size in this region. However, when we look at the NS average, the plateau offtake rate shoots up to over 12% of the EURo with a steeper decline.
The smaller fields in this region are clearly being produced differently, but why? Could it be the lack of subsea tie back opportunities from these assets in a less intensely developed area leading to unfavourable project economics? What do you think?
Our #Trendoftheweek this week looks at the relationship between water depth of offshore fields and recovery factor.
Our Recovery Factor benchmarks combine rock and fluid properties to predict Recovery Factor of fields. Whilst our benchmarks are a good initial assessment, we can delve deeper and observe the influence of other parameters not explicitly used in the algorithm – such as water depth.
The pink points on the plot are fields in water depths of more than 750m. Due to the added complexity and cost of developing these assets you can see they systematically underperform compared with the prediction from bMark. However…this is not true for all deep-water assets. Using analogues and data-driven workflows in bMark operators can understand the driving factors in recovery factor and ensure that they are maximising the value of their assets.
Using large volume datasets like those in bMark enables trends to be seen and informed decisions to be made. Our machine-learning derived benchmarks predict recovery factor, well numbers and production rates and can be used at every part of a field life to maximise reservfes. Contact us today to see how bMark™ can empower your workflows
You might expect there to be many differences in how oil and gas assets are developed and managed across the world, based on influences like drilling costs, drive mechanism preferences and energy requirements. But what does the data show?
By taking two highly productive regions – the North Sea (NS) and the Gulf of Mexico (GoM) – we can start to analyse if any systematic trends are apparent. We are visualising, on this plot, average profiles generated based on different filters applied in bMark™. Normalised parameters are used on both the x and y axis to account for variation in assets such as size and age.
We can see that the larger fields (>300MMstb) behave very similarly in both regions with plateau offtake rates around 8-9% of the EURo and a steady decline from around 40% EURo.
When we add back in the smaller fields in both regions, the story is very different. The GoM average remains similar to the previously identified trends, implying that development is consistent regardless of field size in this region. However, when we look at the NS average, the plateau offtake rate shoots up to over 12% of the EURo with a steeper decline.
The smaller fields in this region are clearly being produced differently, but why? Could it be the lack of subsea tie back opportunities from these assets in a less intensely developed area leading to unfavourable project economics? What do you think?
Our #Trendoftheweek this week looks at the relationship between water depth of offshore fields and recovery factor.
Our Recovery Factor benchmarks combine rock and fluid properties to predict Recovery Factor of fields. Whilst our benchmarks are a good initial assessment, we can delve deeper and observe the influence of other parameters not explicitly used in the algorithm – such as water depth.
The pink points on the plot are fields in water depths of more than 750m. Due to the added complexity and cost of developing these assets you can see they systematically underperform compared with the prediction from bMark. However…this is not true for all deep-water assets. Using analogues and data-driven workflows in bMark operators can understand the driving factors in recovery factor and ensure that they are maximising the value of their assets.
Using large volume datasets like those in bMark enables trends to be seen and informed decisions to be made. Our machine-learning derived benchmarks predict recovery factor, well numbers and production rates and can be used at every part of a field life to maximise reservfes. Contact us today to see how bMark™ can empower your workflows
The bMark™ Global Subsurface Database includes data on over 51,000 assets. With data on over 230 properties gathered covering rock and fluid properties as well as development metrics, heterogeneity indicators and reserve figures.
Our #Trendoftheweek this week looks at the relationship between Porosity and Permeability. Filtering to the North Sea and by colour categorising the dataset by Reservoir Lithology we can see the stark difference between the Chalk fields of the Southern North Sea and the dominant clastic reservoir trend.
Using large volume datasets like those in bMark enables trends to be seen and informed decisions to be made. Contact us today to see how bMark™ can empower your workflows.
The size of an oil field can often influence the way in which the field is developed, and what we might expect in terms of production forecasting.
This week’s #TrendoftheWeek looks at large (>2Bstb), mature (over 70% through expected production) oil fields. Individual production profiles from these fields are averaged to generate typical production curves. The carbonate field average, dominated by oil giants of the Middle East and Mexican Gulf of Mexico, displays a lengthy plateau followed by a very sharp drop off. In comparison, the clastic field average, dominated by Russian, North Sea and Venezuelan assets, displays a shorter plateau with a steadier decline.
Interestingly, both averaged profiles display a similar uptick in production ~75% through field life. What is causing this systematic trend?
By looking at several specific examples, where this uptick is pronounced, the reasoning for late-life increased production is varied. Some, like the Forties field in the North Sea are based on new Operatorship, bringing fresh eyes and ideas to the table. Others are due to a significant shift in field management like a change to an EOR program, based on favourable economics.
Where else are large fields coming up to this maturity point, and what can they learn from the more mature analogous fields?
Request a Demo: See how bMark‘s advanced analytics can help you uncover critical production trends and optimize field management strategies. Request your demo today!
This week’s #TrendoftheWeek comes from bMark™>CCS – our module for visualising global data and screening sites for Carbon Capture and Storage projects.
Last week’s #TrendoftheWeek highlighted the use of different drive mechanisms in hydrocarbon extraction. Here, in blue, we filter the bMark™ subsurface database using the Society of Petroleum Engineers (SPE) criteria for CO2 Enhanced Oil Recovery (EOR) to highlight fields with potential for miscible CO2 injection.
In orange, we can see data for CO2 emission sites in South East Asia sized based on their output (Mtpa). Visualising this spatial trend of CO2 output we can look at where CCS hubs may develop linked to EOR projects.
Request bMark™>CCS Free Demo
This week’s #TrendoftheWeek, built from bMark™ data, focuses on the differences around the world in how pressure in oil reservoirs is managed via the reservoir drive mechanism.
Producing oil efficiently requires management of pressure within the reservoir with the ideal reservoir production pressure typically maintained stable and just above the point at which gas will escape from the oil, known as the bubble point pressure. Determining, predicting and maintaining the optimal pressure conditions for an oil field is a large part of a Reservoir Engineer’s job.
In some basins Operators are lucky enough to have natural pressure support mechanisms such as aquifer influx and gas cap expansion which can help to provide pressure support to balance the loss of pressure from oil extraction however this is not always the case and in many cases without adding additional pressure support to enhance the Natural Drive mechanisms then reservoir pressures will decline and reserves will be lost.
To support pressures it is common to inject water and/or gas to support pressures artificially, known as secondary drive. In some cases Operators may go beyond secondary drive and add heat, polymers, microbes or chemicals to injected fluids to achieve “tertiary” drive, often also called enhanced oil recovery or EOR.
Application of secondary and tertiary (EOR) drive mechanisms in oil fields increases the reserves recovery of a field but comes with additional operational costs, complexities and technological requirements all of which must be balanced in each case against the incremental reserves recovered.
Looking at our chart the rest of the world lags North America in application of secondary drive – what reserves uplift potential could there be if this gap was closed?
bMark™ can help Operators understand where analogues to their field have benefited from secondary & tertiary recovery and what application in their field might mean for added reserves.
Stay in the loop with our latest weekly trends and insights! Click here to read this week’s update and explore more.
Only with large analogue datasets can we get the best insights. Predictive benchmarking in bMark™ harnesses machine learning to analyse asset performance and enables user to maximise the value of their assets.
Our Recovery Factor benchmarks combine rock and fluid properties to predict Recovery Factor of fields and reservoirs. bMark™ also includes predictive models for Number of Wells and Peak Rates. These insights can be used at any point of field maturity and in any field in the world.
In our #trendoftheweek this week we look at the Ghawar in Saudi Arabia, the largest conventional oil field in the world, comparing recovery factor performance against our Global benchmark. Shown in black, at a field level we see good performance with the field narrowly above the bMark™ prediction.
But this only tells a small part of the story…we always encourage users to benchmark their assets at a reservoir or flow-unit level. The orange points represent the reservoir units that make up the field. Whilst 4 of the reservoirs are performing well against their benchmark prediction, there are 2 reservoirs that may have potential for an increase in Recovery Factor and therefore an increase in reserves.
Are you harnessing data-driven insights and maximising the value of your assets?
Discover the power of bMark™ firsthand! Request a demo today to try it yourself and unlock valuable insights for your assets. Contact Us
This week’s #TrendoftheWeek, built from bMark™ data, celebrates the technological achievements of the drillers in the Oil & Gas Industry with a chart displaying how the boundaries of ‘how deep we can go’ have been continuously pushed back over the course of the 20th and early 21st Centuries.
Technological advancements have always propelled the oil and gas industry to drill deeper into the Earth’s crust. Innovations in drilling techniques, equipment, materials, telemetry and real-time data analysis have expanded depth capabilities significantly.
Drilling deeper has become essential as traditional reserves dwindle, prompting the industry to pursue harder-to-reach oil fields. Meeting global energy demands has necessitated accessing these untapped resources, driving the push for innovation.
Despite the complexities and higher costs associated with deeper drilling, the potential rewards in securing future energy supplies make it imperative for the industry to invest in technological advancements continuously. How far will we go in the future?
In the spirit of Ramadan, let’s shine a light on the Ramadan field, discovered in May 1974 in the Gulf of Suez, Egypt. Harnessing the power of bMark™, we compare the field to its peers in the of Gulf of Suez, a mature province where exploration continues to yield new discoveries.
Here we visualise Porosity vs Permeability data from over 100 fields and reservoirs, extracted from the bMark™ subsurface database. With a porosity of 15%, Ramadan sits just below the mean porosity of 18% observed in the Gulf of Suez. This comprehensive dataset allows for the validation of pre-drill expectations, providing valuable insights into subsurface trends.
Ready to explore the power of bMark™ firsthand? Get in touch with us today to schedule a demo and discover how bMark™ can enhance your workflows with its vast database and powerful insights.
Are we becoming more efficient?
One thing consistently strived towards in the energy industry is efficiency. Both in terms of time and cost. But this can often be a very difficult thing to quantify and prove.
Using the large database in bMark, for offshore fields in the mature North Sea region, we investigated the number of months between discovery and first production of a field. We can see clearly a systematic reduction in this metric through the decades from fields discovered in the 1960s to 2010s, likely driven by improvements in technology, economies of scale and existence of prior infrastructure.
Interestingly, although the mean continues to fall throughout the decades, the spread from upper to lower quartile from discoveries in the 2010s increases comparatively to the 2000s. Could this be a knock on from volatility in markets in the 2010s impacting decision making?
The slowing of progress in this metric highlights the importance of other efficiency factors such as production technology innovation and development ramp up after first production.
We can use similar trends from basins around the world to benchmark development planning assumptions for future projects, ensuring that forecasts are reasonable and in line with analogues.
Carbon storage projects typically aim to maintain injected CO2 in a supercritical state, which, for CO2, is achieved at temperatures exceeding 88°F and pressures greater than 1057 psi. In this supercritical state, CO2 displays properties of both a gas and a liquid, sharing the density of a liquid but possessing the viscosity typical of a gas. The primary advantage of storing CO2 in a supercritical state is the substantial reduction in necessary storage volume, allowing for higher storage capacity.
For screening purposes, a top structure depth of 800mTVDss serves as a typical guideline to determine whether a reservoir will have the required pressure and temperature conditions. However, our bMark™ trend of the week reveals that while this guideline is generally reliable, it does not always ensure that a reservoir will fall within the supercritical window.
We have identified over 450 global fields and reservoirs that exceed this depth criteria but are outside the supercritical CCS window. Interestingly, many of these highlighted fields are concentrated in the Volga-Urals region, potentially posing challenges for efficient decarbonization efforts.
Although only around 3% of the total dataset with depths exceeding 800m would be unsuitable, this exercise emphasizes the importance of employing a comprehensive screening workflow, such as those offered by bMark™>CCS, to ensure that specific fields are technically feasible.
The Orange Basin, Namibia, is a particularly exciting exploration region, following several recent successful discoveries.
But in such an immature basin, can we predict the likely volumes in place?
bMark™ shows the expected range to be from 20-3000MMstb based on a P10-90 range, with the P50 volume of 200MMstb.
The extensive global database available in bMark™ can be used to identify analogous basins, in this case Rifted Passive Margins containing similar aged reservoirs. Volumetric data can then be interrogated to provide a range and distribution of volumes in these basins, which can be linked with other influencing factors, such as water depth, facility type or even Operator.
Request a bMark™ demonstration or trial today to understand how big data can add value to your workflows.
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Greenfield oil development offshore Mexico; 1500MMstb in place
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