Big Oil Costs Can't Go Much Lower

The space for cost reduction among the supermajors is dwindling. What now?

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In a world of automation cost can always go down but just more slowly

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(edited)

Logically, when cost reduction is no longer a card that can be played, the next step in the evolution is "consolidation," where the super-majors put their immense capital and borrowing power to work, swallowing up minor players - and their reserves plays. 

You see that in every industry.  Look at what happened in airlines, where large numbers of the little guys got bought up by the mega-carriers, so that today only three players control some 85 to 90 percent of the market. 

Edited by Jan van Eck
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12 hours ago, Marina Schwarz said:

The space for cost reduction among the supermajors is dwindling. What now?

From where I am which is working in the industry costs are actually going up as shortage of trained workers is forcing rates back up. Oil companies cannot keep costs down when demand rises for personnel and equipment. They have cut rates for a few years as people were desperate now there is a shortage as many experienced people have left the industry in the last few years and have not been replaced. Happens every time this is my 3rd oil cycle.

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Upon re-reading this, I realize it's a bit long and takes the  conversation in a bit of a different direction.  It's done though, so I'm posting it. 

Cost need not go down forever.  It's sufficient to go down enough that OPEC is afraid of controlling prices for fear they'll lose market share.  My understanding is that that's already happening. 

To wit, the quantity of "reserves" - where there are different kinds of reserves defined different ways - depends heavily on the price of oil.  At $20/bbl, world reserves are dangerously low and mostly found in politically unstable countries.  At $120/bbl, not only do we have vast unconventional reserves everywhere, but we can also manufacture as much oil as we want from coal, natural gas, biomass, trash... pretty much anything carbon-based.  $120/bbl oil is effectively unlimited.  Somewhere between $20/bbl and $120/bbl, there's a price at which we can tell OPEC where to shove it.  Excepting occasional extenuating circumstances, prices remain stably below that point. 

When we talk about lowering production costs, what we're actually talking about is lowering the price at which OPEC becomes irrelevant.  I.e. the price at which we have sufficient reserves to replace their production should we feel so inclined.  When shale fracking started, maybe that was around $120/bbl.  Today, maybe it's around $70/bbl.  With incremental improvement and new technologies (automation, Utah oil sands, anything-carbon-to-liquids technologies, CO2 injection, etc), maybe it goes as low as $50/bbl. I would argue that, while the low-hanging fruit has been picked, incremental improvements still have significant political effects.  With today's technology, OPEC's ability to control long-term prices is gone.  They've lost.  They can create a price spike, but only at the cost of permanent loss of market share.  Moving forward, every efficiency improvement and new technology lowers the equilibrium price, carving yet another chunk out of their budgets and lowering the ceiling on oil prices.  For that reason, fraction-of-a-percent improvements matter.

On a related note, there's much talk of the Permian being temporary, but I think that risk is overstated.  If you look at the predicted production decline rates, you see rapid initial decline followed by slow-and-steady decline ad infinitum.  The well is only shut off when the cost of running it exceeds the revenue it produces.  This is where automation comes in: a huge chunk of well cost is operating, inspecting, and maintaining in-place equipment.  Automation technology - which oil industries are rapidly fielding - reduces exactly those costs, allowing shale wells to produce slow-and-steady for longer.  To give you an idea, ranchers and oil producers are signing contracts that assume 20+ years of production from a given well.  It's not a sure thing, but the most intelligent, informed people with skin in the game are betting on 20+ years.  I consider that valid information. 

Given shale wells that can produce for decades, consider that we're at the beginning of this shale revolution.  The number of wells being drilled is still large relative to the number of wells in existence, which means shale oil production rises and falls with drilling activity.  However, at some point, production from old-and-steady shale wells will exceed production from new-and-fast wells.  We could have enough old-and-steady wells to keep the Permian pipelines flowing with minimal drilling activity.  For decades. 

Having built out Permian infrastructure also makes new plays and incremental drilling economical.  Maybe we drill wells in less valuable Permian fields because the infrastructure is already there.  Maybe we extend a pipeline a bit into New Mexico and develop entirely new fields.  Maybe ongoing exploration discovers yet more fields (after all, reserves are based on what we've bothered to find thus far).  The shale story isn't over yet. 

 

Stepping away from details, I'd like to offer an observation I made about warfare and how I think it applies to oil markets.  We portray warfare as simple, cut-and-dried events with defined starting points, defined players, defined tools, defined ending points, and clearly understood outcomes.  It's all neatly packaged for consumption so the Average Citizen(TM) will reach politically desirable conclusions.  This is commonly known as "fake news".  In reality, warfare is tens of thousands of intelligent predators wielding hundreds of unique weapon systems in a life-and-death struggle that drives them to their limits.  As these predators hunt each other, they learn.  They develop new tactics.  They see possibilities where others see nothing.  They become ruthlessly competent and frighteningly creative.  Just to make it interesting, brilliant minds continuously throw new means of destruction into the arena.  THAT is warfare, and it's ruled by the gods of chaos. 

It's the same with oil markets: tens of thousands of brilliant predators vie for power and influence in a game played with money in lieu of bullets (Ostensibly, anyway).  Kings, presidents, executives, lawyers, powerful corporations, wealthy men, scientists, engineers, legislatures, lobbying groups - they're are all adding their personal touch of creativity to the game.  With the gods of chaos out to play, it's hard to say how, exactly, things will go. 

Despite all that, there are invariants.  Warfare is governed by brute force and oil markets by the ironclad law of supply and demand.  If we want to make tentative statements about what a particular technology will-or-will-not do, we can check its effect on supply & demand.  I.e. its effect on the people playing the game.  To answer the original question: oil majors have picked the low-hanging fruit on one particular set of technologies while operating in particular types of oil fields that exist in the regions we happen to have explored for oil.  With this particular opportunity exhausted and oil prices steadily high, the brilliant predators who run oil majors will return to their playbooks and decide what to hunt next.  Maybe the MBA's will go on an M&A bender as Jan suggested.  Maybe the breakeven point is low enough and prices steadily high enough that oil majors will focus on expansion.  Now that OPEC's power is broken, maybe the US government will help oil majors gain market share by toppling OPEC regimes one-by-one.  It's hard to say what, exactly will transpire, but we do know this: the game is determined by supply and demand, supply and demand are influenced by break even points, and today's lower break even points present interesting opportunities to powerful players. 

My guess?  After decades of OPEC screwing with the world because it thought itself untouchable, low break evens have rendered them vulnerable.  To eliminate their dickery, make an example of them, and steal their market share, I would expect developed, oil-exporting nations to pick them off one-by-one as their supply can be replaced.  China might throw them a lifeline, but that in itself will be a form of punishment - and may not be effective. 

Whatever the case, it's going to be interesting.  Grab some popcorn.
http://farm3.staticflickr.com/2684/4420391361_4ce70f5b9e_z.jpg?zz=1

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On 9/12/2018 at 11:04 AM, Sebastian Meana said:

In a world of automation cost can always go down but just more slowly

Automation is not exactly free, so I'm not sure this is the case. And then there's cybersecurity, which also comes at a cost. Also, we need to consider acreage quality. The best--lowest-cost--may already be depleted. Interesting topic, in any case.

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7 hours ago, Marina Schwarz said:

Automation is not exactly free, so I'm not sure this is the case. And then there's cybersecurity, which also comes at a cost. Also, we need to consider acreage quality. The best--lowest-cost--may already be depleted. Interesting topic, in any case. 

That's a good point: cost won't necessarily go down because there are many variables at play. 

I do think there's a lot in favor of lower costs though.  E.g. advances in automation leverage vast resources from other industries.  Even if oil companies do nothing, the cost of automation and cybersecurity will plummet because other people are working on it.  The oil industry need only deploy technology as it becomes available.  Then there's the value of experience.  The more we drill, the more we learn about drilling.  The more we make drilling equipment, the more we learn about making drilling equipment.  That doesn't require vast R&D expenditures or major breakthroughs; when you put intelligent, competitive people on the job, it just happens

So we're learning at some rate and depleting the best oil fields at some rate.  In the long run, my guess is we win because the amount of oil we can economically access is a non-linear function of how good we are at extracting it.  E.g. cutting costs by 20% might increase economical reserves by 100%.  Or 200%.  Or 1000%.  I don't know what that number is exactly, but I know it's not linear.  We don't have to improve forever; we just have to become good enough that reserves are plentiful. 

Also, we don't have to drill forever.  It's sufficient to drill for oil until we can economically synthesize oil from any readily available carbon source.  We can already do this at $100/bbl.  The next round of technologies are aiming for $50/bbl, and there's good reason to believe they'll achieve it.  Once that happens, it doesn't matter if the shale fields decline.  So again, we don't have to be perfect; we just have to be good enough for long enough.

The future looks bright. 

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Gee, maybe we shouldn't be freezing or reducing car efficiency standards after all. 

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On 9/12/2018 at 12:42 AM, Marina Schwarz said:

The space for cost reduction among the supermajors is dwindling. What now?

Cost reduction is to be "caused & created" at all levels and in all aspects of management & operations.

Reduction of costs of consumables, goods, services and working with the service providers, contractors, sub-contractors, vendors etc to keep costs contained and manageable while everyone in the chain is able to make a decent profit, pay good wages and perks to their employees, operate in a safe, stable environment, protect the environment, have sustainable stable production volumes that meet the supply and demand scenarios and in line with the crude and various other hydrocarbons streams the companies produce and market.

Being nimble and being able to adjust to changing operational environments, geopolitical factors, technological advances, finding and integrating synergies in various different departments, people resources(employees) , combining the right synergy of technologies across the board to achieve better output and efficiencies - encouraging and rewarding employees to acquire additional skills to further their departments output, results and growth.

With advanced techs , employers may be forced to lay off certain sets of employees but they should think beyond the purported cranial limitations and redeploy as many of those sets of employees to advance the use and better integration and perhaps even make them better in the application of those techs.

And these apply to all aspects of the energy industry, upstream, midstream, downstream and all associated and allied industries providing support, services and goods.

_______________________________________________________________________

"

Fracking robots in the works as Halliburton ‘digitises’ oil field

Written by Bloomberg - 22/08/2018 9:42 am

 

Bots already are used to vacuum floors, build cars and do heart surgery. Now, Halliburton Co. wants to add fracking to the to-do list.

The world’s biggest provider of the technique that unlocks oil and natural gas from shale rock has a vision of push-button fracking that’s still years in the making. But for now, the Houston-based contractor unveiled a new service that will help move in that direction.

Tested in fields globally including the Permian Basin of West Texas and New Mexico, Halliburton’s Prodigi AB service uses data and computer coding to automatically crank up the pumps to the necessary level in order to blast water, sand and chemicals underground to released trapped hydrocarbons.

 

“This is new territory for the industry,” Scott Gale, who oversees the new fracking service at Halliburton, said in an interview on the sidelines of Halliburton’s annual technology conference in Houston. “We recognize that digital technologies are descending on our industry, so expectations are high.”

Typically, workers have to rev up the pumps manually, which can lead to inefficiency and delays, Gale said. Before wells are fracked, automated rigs are already being used to drill them.

"

 

 

"

Oil and Gas: ready for big data?

Written by Andrew Docherty - 18/09/2018 6:00 am

For many in the energy sector, it’s not just potential energy reserves which remain untapped, but also data reserves.

Highlighting that belief, Stephen Ashley of the Oil and Gas Technology Centre recently asserted that companies in the oil and gas sector stand to make significant savings if they can ‘sort out’ their relationship with big data.

Addressing delegates at Aberdeen’s ENGenious conference, Ahmed Hashmi of BP also warned that ‘fixed mind-sets’ are holding the industry back.

So, what are Stephen, Ahmed and others getting at – and is the oil and gas sector really behind on the data revolution?

The argument goes that the industry is currently sat on a wealth of data that isn’t being utilised as best it could. Data gathered in the process of exploration, well development and production for example, produce huge volumes of data. And once a well is established, the monitoring of equipment, as well as oil and gas flow rates and pressures, produces important data about the structures and layers of the Earth’s surface – data which could be harnessed to guide further, smarter exploration.

As the technologies underpinning these processes grow more sophisticated, the data set will only grow larger so, could oil and gas be on the verge of its own big data moment?

This is an important question for those aiming to lead the oil and gas industry into the high-tech times we live in. A cursory glance at other industries reveals the impact that data, and data-driven innovations, are having. Whether it’s digital first businesses that gather huge volumes of data on consumer behaviour, or healthcare platforms and services which can monitor health conditions and lifestyles in near real-time to predict and prevent illness, data is an increasingly powerful, and valuable, tool.

Meeting the challenge of big data is about more than just analytics however, it also presents a unique set of intellectual property (IP) challenges. When data becomes incredibly powerful – imagine for example a data-driven exploration model that outperforms the competition when it comes to scouting for new reserves of gas and oil – protecting that value with IP is vital.

Whereas those in the oil and gas sector will no doubt be familiar with protecting innovation through patents and design rights, these forms of IP are often inappropriate when it comes to protecting digital technology. Computer code for example would more likely be something subject to copyright – like a book or music – and it can be difficult to prove the ‘uniqueness’ of code and attain protection.

While complexities remain however, patenting computer-implemented inventions is no longer considered new or controversial, and these innovations are increasingly central to any IP portfolio. And where vagaries do exist, the legal system is striving to catch up. Later this Autumn will see the European Patent Office (EPO) issue new, wide-reaching guidelines around the protecting of AI software for example, ensuring the law is well placed to deal with a technology which will reshape economies in coming decades.

As data becomes ever more prevalent, the oil and gas sector, like all others, will embrace these new technologies and the opportunities they present. Getting the IP right, and protecting hard-won digital innovation, will be key to future success.

Andrew Docherty, of Marks & Clerk, is a Chartered (UK) and European Patent Attorney

"

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As the oil companies do very little themselves, the overwhelming part of the cost reduction came from squeezing the service sector to operate at below marginal cost rates. It is still too common that rigs get hired on short term contracts at cut-throat rates, and simply dumped when equipment NPT creeps up due to no money for maintenance. How "sustainable" is that?

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Typical topic of an industry that has rewarded performance solely based upon cutting costs as opposed to producing oil. No one considers that spending more money to increase the oil production may improve the net present value, which is the real measurement. 

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On 9/12/2018 at 2:07 AM, Jan van Eck said:

Logically, when cost reduction is no longer a card that can be played, the next step in the evolution is "consolidation," where the super-majors put their immense capital and borrowing power to work, swallowing up minor players - and their reserves plays. 

You see that in every industry.  Look at what happened in airlines, where large numbers of the little guys got bought up by the mega-carriers, so that today only three players control some 85 to 90 percent of the market. 

We saw consolidation with the super majors in the 90s with Exxon & Mobil , BP-Amoco, Chevron-Texac0 and the others. Recall when back in the day there were "7 Sisters" ?

Consolidation also happened in the shale patch too during the price downturn and just before that. XOM buying out XTO etc.

And during the price downturn , numerous balance sheet healthy companies gobbled up other companies with not so healthy balance sheets.

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Hi Marina,

Here are some examples that will lead to cost cutting by the majors and will eventually make it to the independents and others.

"

Kongsberg Digital launches their new digital twin at ONS 2018 in Stavanger, Norway, after a successful feasibility study with Equinor.

Enabling value chain transformation in operations

The new twin is a virtual model of unmanned production facilities for oil and gas. Combined with KONGSBERG’s Kognifai solution it becomes a collaborative arena allowing users onshore to explore planned or existing assets offshore. It delivers intimate understanding of operations, behavior, maintenance, costs, performance, and much more. Available on any digital device – from pads to desktops or VR glasses – the twin recreates all the characteristics of real assets in an advanced, data-enriched 3D visualization.

“The digital twin for production facilities allows us to help our customers transform the way they do business and operate in complex industrial settings,” observes Hege Skryseth, executive V.P. of KONGSBERG and President of Kongsberg Digital. “Integrating previous disparate data together in a single, secure and user-friendly cloud-based platform will provide a multitude of benefits to our customers when connected to our digital platform. Everyone from the engineer in the control room to the CEO in her office will get real time insight into platform operations, and will be able to make better informed decisions.”

Reducing risks and diminishing environmental footprints

The results of the feasibility study with Equinor prove that dynamic simulation is key to the potential of the digital twin. When 3D and physical models, enterprise systems, and process simulators are integrated into the twin, the operator can leverage historical, real-time, and predictive data to optimize workflows and specific operations throughout the asset’s lifecycle.

Using the digital twin will improve design quality and processes, enhance cross-discipline collaboration, reduce project and operational risks, and diminish overall environmental footprint. It will also enable autonomous, unmanned, and remotely operated assets for oil and gas production facilities.

The digital twin is a major leap forward for collaborative processes in oil and gas production. It will lead to improved decision support and introduce tangible operational and financial efficiencies.

The new digital twin is on show at KONGSBERG’s stand #7280 in hall 7 at the ONS and is a duplicate of a physical oil and gas production facility.

"

 

 

Gardner Denver releases newest pressure pumping fluid end technology

-- Gardner Denver Petroleum & Industrial Pumps, the only total solutions provider to the drilling, well servicing and frac pumps market, announced the launch of GDNX, the next generation of fluid end technology.

GDNX features include:

  • Redline consumables. This revolutionary series of aftermarket parts extend product life by up to 3.5x.
  • Superior fatigue life. Patent pending cross-bore design that reduces operating stress and maintenance intervals by 3.5x when compared to competitors.
  • Compatibility. Fit, form, and function of the GDNX are the same as the SGWS series, meaning it’s a direct fit to existing 2250/2500 pumps. o All suction manifold, discharge flange and tie rod connections will remain unchanged from SGWS fluid ends, allowing GDNX fluid ends to serve as a direct replacement for SGWS fluid ends.
  • Proven Falcon Technology. The service-friendly design reduces maintenance time for valve, seat, plunger and packing changes.
  • Ease of maintenance. No alignment requirements to suction covers and no special tooling required to install.
  • Stainless steel. The GDNX fluid end is built to last.
  • Service & Support. 24/7 aftermarket service and support anytime and anywhere you need it.

GDNX is available for immediate shipment to fit all manufactured models of Frac pumps.

9/18/201
 

 

 
 
 
 
 
 
 
 
 
 
 

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Just now, ceo_energemsier said:

Hi Marina,

Here are some examples that will lead to cost cutting by the majors and will eventually make it to the independents and others.

"

Kongsberg Digital launches their new digital twin at ONS 2018 in Stavanger, Norway, after a successful feasibility study with Equinor.

Enabling value chain transformation in operations

The new twin is a virtual model of unmanned production facilities for oil and gas. Combined with KONGSBERG’s Kognifai solution it becomes a collaborative arena allowing users onshore to explore planned or existing assets offshore. It delivers intimate understanding of operations, behavior, maintenance, costs, performance, and much more. Available on any digital device – from pads to desktops or VR glasses – the twin recreates all the characteristics of real assets in an advanced, data-enriched 3D visualization.

“The digital twin for production facilities allows us to help our customers transform the way they do business and operate in complex industrial settings,” observes Hege Skryseth, executive V.P. of KONGSBERG and President of Kongsberg Digital. “Integrating previous disparate data together in a single, secure and user-friendly cloud-based platform will provide a multitude of benefits to our customers when connected to our digital platform. Everyone from the engineer in the control room to the CEO in her office will get real time insight into platform operations, and will be able to make better informed decisions.”

Reducing risks and diminishing environmental footprints

The results of the feasibility study with Equinor prove that dynamic simulation is key to the potential of the digital twin. When 3D and physical models, enterprise systems, and process simulators are integrated into the twin, the operator can leverage historical, real-time, and predictive data to optimize workflows and specific operations throughout the asset’s lifecycle.

Using the digital twin will improve design quality and processes, enhance cross-discipline collaboration, reduce project and operational risks, and diminish overall environmental footprint. It will also enable autonomous, unmanned, and remotely operated assets for oil and gas production facilities.

The digital twin is a major leap forward for collaborative processes in oil and gas production. It will lead to improved decision support and introduce tangible operational and financial efficiencies.

The new digital twin is on show at KONGSBERG’s stand #7280 in hall 7 at the ONS and is a duplicate of a physical oil and gas production facility.

"

 

 

Gardner Denver releases newest pressure pumping fluid end technology

-- Gardner Denver Petroleum & Industrial Pumps, the only total solutions provider to the drilling, well servicing and frac pumps market, announced the launch of GDNX, the next generation of fluid end technology.

GDNX features include:

  • Redline consumables. This revolutionary series of aftermarket parts extend product life by up to 3.5x.
  • Superior fatigue life. Patent pending cross-bore design that reduces operating stress and maintenance intervals by 3.5x when compared to competitors.
  • Compatibility. Fit, form, and function of the GDNX are the same as the SGWS series, meaning it’s a direct fit to existing 2250/2500 pumps. o All suction manifold, discharge flange and tie rod connections will remain unchanged from SGWS fluid ends, allowing GDNX fluid ends to serve as a direct replacement for SGWS fluid ends.
  • Proven Falcon Technology. The service-friendly design reduces maintenance time for valve, seat, plunger and packing changes.
  • Ease of maintenance. No alignment requirements to suction covers and no special tooling required to install.
  • Stainless steel. The GDNX fluid end is built to last.
  • Service & Support. 24/7 aftermarket service and support anytime and anywhere you need it.

GDNX is available for immediate shipment to fit all manufactured models of Frac pumps.

9/18/201
 

 

 
 
 
 
 
 
 
 
 
 
 

Production gains through the reuse of produced water in fracturing ///

The rapid expansion in the use of hydraulic fracturing to unlock unconventional hydrocarbons over the last five years has created significant challenges in water management. The U.S. Environmental Protection Agency (EPA) estimates that 3.3 Bbbl of water were used in 2010 for fracturing in North America. Costs associated with the management of water, from sourcing through disposal, have been estimated to comprise as much as 15% of the overall cost of a well.1 Reuse of produced and flowback water to reduce costs has been an area of focus within the industry, but the practice has yet to become standard. While cost-effective technical solutions exist to treat these waters for reuse as an alternative to fresh water, a more fundamental question remains: What is the long-term impact, on production, of switching from the accepted practice of fresh water use to the use of produced water for hydraulic fracturing?

 

 

_____________________________________

 

Demand for more wells, more footage with fewer rigs drives drill bit design ///

Drill bits are highly expensive, precisely constructed products, and the fewer of them that are required for a well, the better the margins. The easy oil was produced long ago, and operators find themselves caught between sagging oil prices and more difficult formations in a continuous effort to make well drilling economical. Bit designers have stepped up to the challenge.

 

___________________________________________________________________________________________

 

Siemens PLM Software has announced, with Bentley Systems, an integrated solution for enterprises to deliver capital projects more efficiently, combining the Teamcenter portfolio with Bentley’s ProjectWise and its Connected Data Environment (CDE). Teamcenter is the world’s most widely used product lifecycle management (PLM) system, and ProjectWise is the project delivery collaboration platform for 43 of Engineering News Record’s global Top 50 Design Firms. The new offering continues Siemens’ and Bentley’s strategic alliance that was announced in 2016, and will uniquely extend enterprise visibility across program management of capital project engineering and construction.

“In going digital, the work of engineers and constructors is increasingly about the digital context and digital components around, and within, their infrastructure projects,” said Greg Bentley, CEO of Bentley Systems. “As we industrialize project delivery, it is exciting for us to be working with Siemens to extend the reach of our CDE’s digital workflows beyond individual capital projects. With the Teamcenter PLM integration, the connections of project digital twins can now both expand into their enterprise context, and drill down into their manufactured components—advancing infrastructure through digital DNA!”

The leading capabilities for systems engineering and requirements management within Teamcenter, and lifecycle simulation of engineered components, are now complemented by Bentley’s CDE to take advantage of a project digital twin. Project digital twins automate digital alignment and change synchronization across the project supply chain, enabling continuous and comprehensive status reviews. Digitalizing a plant from the beginning of a project enables the aggregation and dissemination of data in a scalable and manageable fashion. By connecting digital twins with a consistent digital thread, companies can reduce project delivery costs and avoid cost overruns, and can improve operational margins by increasing plant productivity and reducing operational overhead. Enterprises can now achieve consistent digital workflows that span project economics, program management, and project controls to speed up capital project delivery, reduce cost overruns, and improve fit-for-purpose project outcomes.

In the energy and utility industries, for instance, given current energy forecasts, companies need to work more efficiently and cost-effectively when implementing capital improvement projects. Traditionally these extremely complex and expensive projects have many groups, beyond engineering and construction, working independently to drive the project forward. Extending Teamcenter through project delivery, the CDE enables visibility along digital threads of connected 2D and 3D models, dynamically managed to reflect project status. This allows for the continuous assimilation of design and engineering data, to be visually and analytically accessible as appropriate by team members across the wider enterprise and supply chain. Incorporating capital project engineering and construction models in this integrated way enables diverse simulations throughout the project management process to anticipate real-world issues, and more informed decision-making by virtue of real-time understanding of the impact of any design change. The solution will be available to the market beginning in early 2019.

“Owner/operators and engineering, procurement and construction (EPC) firms in the industry need to lower costs and deliver projects more efficiently, and this new digital solution facilitates data-driven business processes for the optimization of projects and the plant,” said Tony Hemmelgarn, CEO of Siemens PLM Software. “Powered by the digital twin, this solution allows engineering data to flow between capital project stakeholders, and will support a broad set of industry use cases.”

______________________________________________________

 

 

 

 

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__Some more cost savings____________

In collaboration with Cognite and Framo, Aker BP intensifies the digitization of offshore operations; new smart service contract will change the traditional approach to maintenance.

The Ivar Aasen platform in the North Sea provides Aker BP with more than just oil. It also transmits vast volumes of data back to shore. The interpretation of this data is now set to make the platform among the most technically advanced in the world.

“Aker BP’s vision is to digitalize all our operations from cradle to grave. Key elements are transforming business models and activities through digital technologies and the liberation of data flows. The smart service contract with Framo and Cognite is an important milestone on this journey, and underpins our ambition to take the lead in digitalization,” says Lars Atle Andersen, V.P., operations – technology & digitalization in Aker BP.

A successful collaboration with suppliers

By using Cognite’s data platform, contextualized live data is made available from Ivar Aasen. This provides Framo, the supplier of pumps to Ivar Aasen, real-time access to data from their equipment.

“With Cognite making live and contextualized data available, we at Framo are able to create our own ‘apps’ to predict the status of our equipment, allowing us to plan efficient maintenance. The new system sends intelligent data on our pumps, so we can predict how the pumps will perform in the future,” says Trond Petter Abrahamsen, managing director of Framo Services AS.

The overall goal of the collaboration between Aker BP, Cognite and Framo is to change the traditional approach to maintenance. Continuous flow of live offshore data allows for onshore monitoring of equipment replacing unnecessary scheduled maintenance activities with maintenance when needed.

This also calls for a new approach to agreements, and on Wednesday, August 29, a special smart service contract between Aker BP and Framo Services will be signed.

“The newly available insights of how the pumps of a specific installation are functioning, results in more efficient maintenance. While our service agreements previously just defined hourly rates, we will now focus on uptime. This is something completely new for us and has required the design of new smart contracts with Aker BP”, explains Trond Petter Abrahamsen.  

Profitable at $35 per barrel

Aker BP will continue to digitalize their offshore operations, and the company’s objective is to carry out profitable development projects, even at oil prices below $35/bbl. Cognite's data platform is a core enabler for these ambitions. Cognite liberates and organizes Aker BP’s industrial data to create a digital representation of the industrial reality, both retrospectively and in real-time. It enables Aker BP to extract useful insights on its operations but also to share its data and insights with partners like Framo and to enable new services and business models.

“The more we share, the better. If we can apply this technology in all our fields, our operations will improve. We are confident that this is a smart move. That's why we are clearly stating what we want to achieve and hope that many others will follow”, says Lars Atle Andersen from Aker BP.

____________________________________________________________________

 

BP announced today that it has successfully deployed Plant Operations Advisor (POA), a cloud-based advanced analytics solution developed with Baker Hughes, a GE company, across all four of its operated production platforms in the deepwater Gulf of Mexico.

The announcement comes after an initial deployment of POA proved the technology could help prevent unplanned downtime at BP’s Atlantis platform in the Gulf. The technology has now been successfully installed and tested at BP’s Thunder Horse, Na Kika and Mad Dog platforms – and it will continue to be deployed to more than 30 of BP’s upstream assets across the globe.

“BP has been one of the pioneers in digital technology in our industry, and co-development of Plant Operations Advisor with BHGE is a key plank of modernizing and transforming our upstream operations,” said Ahmed Hashmi, BP’s global head of upstream technology. “We expect the deployment of this technology not only to deliver improvements in safety, reliability and performance of our assets, but also to help raise the bar for the entire oil and gas industry.”

Built on GE’s Predix platform, POA applies analytics to real-time data from the production system and provides system-level insights to engineers so operational issues on processes and equipment can be addressed before they become significant. POA helps engineers manage the performance of BP’s offshore assets by further ensuring that assets operate within safe operating limits to reduce unplanned downtime.

Now live across the Gulf of Mexico, POA works across more than 1,200 mission-critical pieces of equipment, analyzing more than 155 million data points per day and delivering insights on performance and maintenance. There are plans to continue augmenting the analytical capabilities in the system as POA is expanded to BP’s upstream assets around the globe.

BP and BHGE announced a partnership in 2016 to develop POA, an industry-wide solution for improved plant reliability. The teams have built a suite of cloud-based Industrial Internet of Things (IoT) solutions that have been tailor-fit for BP’s oil and gas operations.

“The partnership between BP and BHGE has resulted in a unique set of capabilities that quickly find valuable insights in streams of operational data,” said Matthias Heilmann, president and CEO of Digital Solutions and chief digital officer for Baker Hughes, a GE company. “Together, we are creating leading-edge technologies to automate processes and increase the safety and reliability of BP’s upstream assets. As we extend the solution globally, this will become the largest upstream Industrial IoT deployment in the world when complete.”

BP is currently in the process of deploying POA to its operations in Angola with additional deployments in Oman and the North Sea scheduled for 2019.

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Maersk Drilling and Aker BP have agreed to a one-year contract to deploy high-performance rig Maersk Integrator on the Norwegian shelf from June 2019. The contract is founded on the alliance that the parties entered into in 2017.

 

The Maersk Integrator will become the first rig to be contracted fully under the scope of the alliance between Aker BP, Maersk Drilling and Halliburton. When the high-performance jackup rig finishes its current campaign on Gina Krog in June 2019, it will go directly to Ula for a new one-year assignment with Aker BP.

The tripartite alliance was announced last year and focuses on working in collaborative relationships, which maximize value for all parties involved. This is established in contracts using a shared incentives model, thereby securing mutual commitment to reduce waste and deliver value. The contracts are based on market-rate terms but add the possibility of a sizeable upside for all parties, based on actual delivery and performance.

In the tripartite jackup alliance, the parties are exploring new ways of collaborating to increase the efficiency of drilling campaigns. In addition to setting up shared goals and incentives, it includes integrated project organisations, aligned safety procedures, and a one-team mindset guided by the principles of ‘best man for the job’ and ‘best for the alliance’.

Maersk Integrator is an XL Enhanced ultra-harsh environment jackup rig that is customised for the North Sea. The rig is currently stationed at Gina Krog field on the Norwegian shelf, where it has been engaged in its first-ever drilling campaign since June 2015. When that campaign finishes in June 2019, the rig will move south to Ula field to deploy for Aker BP. As an integral part of the alliance framework, Halliburton will function as service provider for the new campaign.

“With this contract, we will truly see the value of our alliance as we work together to reduce waste and lower the cost per barrel on Ula. The collaboration between our companies is under continuous development due to the alliance, and we expect to gain more and more mutual benefits from working together in new and innovative ways,” says Tommy Sigmundstad, senior V.P. of Drilling and Wells at Aker BP.

Maersk Drilling, Aker BP and Halliburton entered the joint jackup alliance in November 2017. The alliance aims at lowering the cost per barrel and increasing profitability for the partners through implementation of digital solutions, increased collaboration efficiency, and standardization and simplification of processes. It is formalised in a five-year agreement with the option to extend for an additional five years.

With this contract, Maersk Drilling has added a total of 2,373 days and $313 million to its backlog in 2018.

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I'm with @Sebastian Meana here - costs can come down further in the long run, but it's unlikely they'll come down right now as oilfield services are looking to raise prices for their services in the short run.

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7 hours ago, TomTom said:

I'm with @Sebastian Meana here - costs can come down further in the long run, but it's unlikely they'll come down right now as oilfield services are looking to raise prices for their services in the short run.

The boards and exec.  management of both oil companies (operators/producers) as well as the oilfield services companies, contractors, vendors etc need to get creative for both the short term and long term financial successes of their respective companies, employees and shareholders/owners/partners. They may form JVs to contribute products and services @ the front end and have lower costs to   the operators producers can assist the service companies and contractors in helping with the initial capital resources that would be required of the service companies/contractors to carry out their work. The pay out for the service providers/contractors would come in the form of equity payments/profit sharing and or a percentage of interest calculated based on a certain formula  for the amount of work.service/products provided @ the start of a project to get it into production. The operator/producer pays the agreed equity payments/profit sharing/interest from the revenues generated by the sale of the oil, gas, LNG, NGL's, condensate, refined petroleum product, petchem feedstock or whatever the produced product maybe. It may not work in all circumstances but each or most of the  projects could be tailored to fit these goals.

I have carried out several projects under such JV agreements with service providers/contractors etc and that have worked out very successfully during the price downturn and doing well even now. Halliburton has several such agreements and operational agreements with operators.

During the downturn hundreds of companies went bankrupt, some never to come out of bankruptcy . In cases when certain things could have been salvaged by mutually working on issues it would have been great to be able to see companies  make it through, but then survival of the fittest in all aspects of the industry and at all levels.

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17 hours ago, ceo_energemsier said:

The boards and exec.  management of both oil companies (operators/producers) as well as the oilfield services companies, contractors, vendors etc need to get creative for both the short term and long term financial successes of their respective companies, employees and shareholders/owners/partners. They may form JVs to contribute products and services @ the front end and have lower costs to   the operators producers can assist the service companies and contractors in helping with the initial capital resources that would be required of the service companies/contractors to carry out their work. The pay out for the service providers/contractors would come in the form of equity payments/profit sharing and or a percentage of interest calculated based on a certain formula  for the amount of work.service/products provided @ the start of a project to get it into production. The operator/producer pays the agreed equity payments/profit sharing/interest from the revenues generated by the sale of the oil, gas, LNG, NGL's, condensate, refined petroleum product, petchem feedstock or whatever the produced product maybe. It may not work in all circumstances but each or most of the  projects could be tailored to fit these goals.

I have carried out several projects under such JV agreements with service providers/contractors etc and that have worked out very successfully during the price downturn and doing well even now. Halliburton has several such agreements and operational agreements with operators.

During the downturn hundreds of companies went bankrupt, some never to come out of bankruptcy . In cases when certain things could have been salvaged by mutually working on issues it would have been great to be able to see companies  make it through, but then survival of the fittest in all aspects of the industry and at all levels.

 

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On 9/12/2018 at 12:42 AM, Marina Schwarz said:

The space for cost reduction among the supermajors is dwindling. What now?

What are your thoughts to the info I made available

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(edited)

On 9/12/2018 at 12:42 AM, Marina Schwarz said:

The space for cost reduction among the supermajors is dwindling. What now?

Marina, were you able to read some of my thoughts etc on the matter and what do you think of those?

I guess I should go back and better my profile? but i dont have the time in a given day , i just respond to certain things

but we can , not we , me, but the folks with the knowledge and experience and expertise within the wide array of know hows

educate all of us

I am just one person with a certain experience and exposure and daily decision making that will affect 10 or so years from today!! thank

love this Oil Price community

Edited by ceo_energemsier
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