Oil + Gas Monitor http://www.oilgasmonitor.com Your Monitor for the Oil & Gas Industry Mon, 15 Aug 2016 06:57:26 +0000 en-US hourly 1 https://wordpress.org/?v=4.6.8 It’s a Hungry Market http://www.oilgasmonitor.com/its-a-hungry-market/ Mon, 15 Aug 2016 06:54:10 +0000 http://www.oilgasmonitor.com/?p=11448 Effram Kaplan | Brown Gibbons Lang & Company The broader capital markets are healthy, evidenced by intense investor demand. We continue to observe a strong desire to deploy capital and consummate acquisitions, driven by the availability of inexpensive financing options and surplus of capital—market conditions often compared to the last peak M&A cycle in 2007.  […]

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August 15, 2016
Effram Kaplan | Brown Gibbons Lang & Company
The broader capital markets are healthy, evidenced by intense investor demand. We continue to observe a strong desire to deploy capital and consummate acquisitions, driven by the availability of inexpensive financing options and surplus of capital—market conditions often compared to the last peak M&A cycle in 2007.  A driving force in valuations, which was absent from the last cycle, is a persistent supply shortage of quality opportunities to deploy capital.  Investors have considerable buying power and are responding in kind using acquisitions to accelerate growth.  It’s a hungry market.

The credit markets remain aggressive, with buyers continuing to secure favorable credit terms in a borrower-friendly market as capital providers compete for financing opportunities. Leverage appetite is healthy for companies with attractive credit profiles, and higher leverage levels are accommodating purchase price multiple expansion.

Private equity funds have massive stores of capital waiting to be deployed. The growing capital overhang is fueling a supply/demand imbalance in the market, leaving funds to aggressively compete with each other for limited quality deal opportunities. Ample liquidity is expected to help support M&A activity with investors likely to maintain an aggressive posture in 2016 and into 2017.

The capital markets have started to open up to the oil and gas sector after a historically long period of major challenges. Relatively recent stabilized oil and gas pricing is contributing to improved investor sentiment with early signs that the market may be ridding itself of the “falling knife” cliché:

  • After rebounding from a 12-year low this January, oil prices appear to be stabilizing in a $45/bbl – $50/bbl range. The 2016 rise in oil prices has contributed to an uptick in business activity within our own clients and across the broader market, thus leading to improved investor sentiment towards the sector.
  • Operators have expressed an increased willingness to access the capital markets with reasonable expectations. As a result, the gap between buyers and sellers is becoming more aligned as it relates to value, capital structure, and form of transaction to actuate deals.
  • Capital providers, while cautious given uncertainty in the market recovery and duration of this “stabilization”, understand that for many companies, negatively trending operating results are attributable to a depressed commodity environment and not internal operating issues.
  • Capital flow into the sector is improving, evidenced by steady investment demand in the midstream and downstream segments and soft interest in upstream opportunities. While traditional lending institutions continue to display a reduced risk appetite in the sector, alternative capital providers are increasing their level of participation and offering creative, flexible capital solutions.
  • Oil and gas continues to attract private equity interest, and fund raising is active. Existing platforms with healthy balance sheets have continued to expand via acquisitions. Private equity sponsors invested more than $3.7 billion in 25 oil and gas companies in June alone. Also in the month, fund raising topped $400 million—a continuation of solid activity with $12 billion raised in May. The sector also saw its first IPO filing since 2014. Private equity is looking to capitalize on today’s low-oil-price environment and provide financial solutions across the sector, with the midstream and downstream segments expected to be more active in the coming quarters.

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Electronic Invoicing: What’s in it for Suppliers? http://www.oilgasmonitor.com/electronic-invoicing-whats-suppliers/ Fri, 05 Aug 2016 06:46:46 +0000 http://www.oilgasmonitor.com/?p=11429 Michael Weiss | Oildex Digital transformation. Finance automation. Going digital. Computers and the Internet have revolutionized the way companies communicate and do business. For the most part, it’s the large players, the heavy hitters, those E&P companies that are automating not only their field operations but their office processes to maximize operational efficiencies. How does […]

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August 5, 2016
Michael Weiss | Oildex
Digital transformation. Finance automation. Going digital. Computers and the Internet have revolutionized the way companies communicate and do business. For the most part, it’s the large players, the heavy hitters, those E&P companies that are automating not only their field operations but their office processes to maximize operational efficiencies.

How does finance automation affect suppliers? Suppliers share many of the same challenges as their customers. Maintaining competitiveness, increasing efficiencies, and lowering costs are all important focuses, especially during times of economic volatility. One of the biggest challenges for suppliers, however, is maintaining strong financial health and optimizing cash flow to survive the competitive oilfield services segment.

Unfortunately, 90 days to payment has become a norm in the oil and gas industry while suppliers have to contend with extensive upfront costs including inventory, fuel, vehicle expenses, and labor. Imagine not being able to pay your field staff for three months.

As well, manual processing of paper transactions is a cumbersome, often error-prone process. For suppliers, manually keying information into a system opens the door to errors and costly mistakes that can further delay the approval and payment process.

The first step towards automation for suppliers is electronic invoicing.

The Cost of Doing Business

In oil and gas, buyers often have the power to determine when to pay suppliers. This is highly problematic for suppliers who have reduced cash flow and must contend with many upfront costs. Labor, for instance, is often paid every 14 days while many suppliers wait three months before receiving payment. To be competitive, suppliers need to be ready to go with inventory and prepared to pay transportation costs. Other upfront costs include administration, accounting, and business software.

“Getting paid quickly is not just the cost of capital; it’s the cost of doing business,” says David Yager, principal of Canada-based oilfield services management consultancy Yager Management Ltd. Because producers are essentially “drilling wells on credit”, Yager says suppliers have no choice but to account for risk of fraud and non-payment when determining their prices.

With minimal cash flow, suppliers may become dependent on their line of credit or factoring service. Working capital efficiency is important as debt becomes less attractive with rising interest rates. As opposed to debt, cash extracted from working capital doesn’t have to be repaid and doesn’t add leverage to the balance sheet.

A company’s financial strength is determined by many things including its working capital. Investors will evaluate opportunities based on a supplier’s Days Sales Outstanding (DSO) and cash conversion cycle (CCC) track record. A company with high DSO may be a poor investment choice since work is being performed mostly on credit and cash flow is minimal. Working capital is the most rapid and controllable source of improved shareholder value. Suppliers can work to reduce their DSO by eliminating wasted time in the invoice processing cycle.

Faster Processing and Payments

Electronic invoices are not only quick and easy to submit but also extremely cost effective. Research shows that automated accounts receivables processes result in significant cost savings. Companies can save as much as 80 per cent by eliminating the need for postage, labor, materials, and storage.

An electronic invoicing solution brings many benefits ultimately resulting in faster, more consistent on-time payments and a lower DSO for suppliers.

  • Suppliers see fewer data entry errors and more on-time payments with electronic invoice templates.
  • Electronic invoices are immediately delivered to the appropriate invoice approval staff.
  • Accounts receivable teams no longer need to contact customers about the whereabouts of invoices. Electronic invoices are easily tracked online.
  • Suppliers save time and money with real-time electronic notifications and communications with customers.
  • Dispute notification and resolution is more immediate.
  • Reconciling payments against original invoices is easy with a solution that tracks each invoice’s progress through the system. Some solutions even ensure automatic reconciliation and validation as invoices are submitted and moved through workflow.

Processing efficiencies provide many incremental cost savings, but the benefits of electronic invoicing extend well beyond each transaction. 

Better Forecasting and Improved Relationships

Staying competitive means suppliers require things like access to accurate information as soon as possible, opportunities to optimize working capital, and value-added customer relationships.

With electronic invoicing solutions, companies see increased data visibility for future profitability and planning. Near real-time access to invoice and payment data allows suppliers to more accurately forecast and optimize cash flow.

Increased customer collaboration and communication facilitate better working relationships, ones in which customers may determine electronic suppliers as their suppliers of choice. With less time focused on pushing paper and following-up on payments, the relationship between buyer and supplier becomes more symbiotic with the shared goal of sustaining business and increasing operational performance.

Determining if Electronic Invoicing is Right for Your Company

Investing in technology, specifically during an economic downturn, can be risky, but choosing the right solution can be worth the risk. Suppliers should measure performance and weigh whether processing efficiencies are worth the boost to their bottom line. Some important metrics to consider include Days Sales Outstanding (DSO), Average Days Delinquent (ADD), and Accounts Receivable Turnover Ratio (ART). They should also consider some of the “soft” benefits. For instance, by reducing manual, labor intensive accounts receivable activities, staff will be much happier. As well, audits are much simpler with online document storage and retrieval.

The majority of buyers have figured out how to implement finance automation to not only lower costs and increase processing efficiencies, but also to leverage transactional information for near real-time spend visibility and cost management. The benefits of going digital have been insurmountable to buyers. Why shouldn’t suppliers get a piece of it too?

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Oil Field Automation and Robotics http://www.oilgasmonitor.com/oil-field-automation-robotics/ Wed, 03 Aug 2016 06:51:00 +0000 http://www.oilgasmonitor.com/?p=11433 Chris Niven | Oildex In recent IDC surveys, oil and gas IT professionals reported that the top strategies to cope with low oil prices, with regards to IT investments, are to deploy automation more quickly, complemented by advanced business intelligence and analytics for optimization purposes. IDC Energy Insights believes that robotics and related automation are […]

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August 3, 2016
Chris Niven | Oildex
In recent IDC surveys, oil and gas IT professionals reported that the top strategies to cope with low oil prices, with regards to IT investments, are to deploy automation more quickly, complemented by advanced business intelligence and analytics for optimization purposes. IDC Energy Insights believes that robotics and related automation are integral components of the digital transformation process and need to be included in operational and IT architecture requirements and plans.

Automation of the oil field is rapidly becoming a reality as IT merges with OT and leading manufacturer’s like work closely with communications and network vendors to create an integrated framework environment that supports oil field IoT data. The net objective is to manage the great quantities of oil field data in a platform for purposes of monitoring and managing device operations for improved uptime and also for optimized production.

The oil field environment in onshore shale includes communications in the form of mesh networks such that people, devices, equipment and other resources can be immediately connected to monitor, manage collaborate and perform work as soon as they physically arrive at the site.  Analytics will also play a large part to optimize production as oil field modeling and simulation of key criteria will help determine the best optimization strategies to deploy.

Cognitive computing is one of the rising stars in innovation and a top IT initiative in the industry today.  Cognitive promises the ability to quickly sift through xabytes of oil field-related data to discover a wealth of high-impact opportunities to improve accuracy and performance in the oil field by combining machine-learning with human reasoning and senses of perception. Cognitive processing could very possibly be the foundation of the autonomous robot.

 

Oil and gas technologies will become more ruggedized and costly to operate in the coming future due to hostile, hard-to-reach environments. The offshore oil industry consists of many advanced and complicated equipment, structures, and multi-disciplined work force team members.  With a proper knowledge of oil and gas rig environments, industrial robotics and automation opportunities are less abstract for drilling, and these processes must be analyzed and diligence applied to determine the value of robotics and automation in specific onshore/offshore environments.

Robotics in the onshore oil field is especially valuable when it is a drilling rig capable of moving itself around an oil field from one well location to the next. Here are some of the ways robotics is being used:

  • For drilling, the big opportunity is for entire rigs that can be moved, or move themselves to reduce dramatic costs and increase efficiencies in oil field development. some examples include:
    • A simple implementation is Drilling Structures International uses a John Deere engine in conjunction with a drilling rig to be able to pick itself up and move to the next location.
    • Patterson-UTI has walking rig safety, speed, and efficiency are combined to help our customers execute their multi-well pad drilling programs successfully.
    • At the high-end of capabilities, Robotic Drilling Systems, (RDS) company is developing a drilling rig capable of advanced reasoning, and has signed an information-sharing agreement with NASA to discover how to develop an oil rig to be able to erect itself, drill a well, and then move on to the next well.
    • Shell Oil is leading a new graduate-level engineering program with the University of Texas at Austin on automated drilling

Offshore use of robotics is especially useful for replacing humans to perform tasks at great depths for greater safety, accuracy and efficiencies.  Underwater submersibles are used a great deal for inspection and repair and continue to evolve to be more self-maneuverable and independent to perform a wider range of activities.

  • Robotics are excellent for underwater inspection and repair and some solutions include:
    • RDS has plans to build and leverage a 10 foot, robotic arm with an elbow joint that can perform much of the manual labor of a deckhand and other crew member, with the ability to lift a ton of weight and maneuver it into desired location.
    • MIT is working with oil and gas companies on the next generation of remote underwater vehicles and has created a working prototype of an autonomous underwater vehicles (AUV), with the goal of further developing it into a complete functional ROV, untethered for agility, with advanced functionality, and a complete communication system giving the human operator more data, analytics and greater flexibility and control to go where no man has gone before, and literally do what humans cannot deep below the surface.
    • New robotics solutions will be deployed under the sea as man learns to bring computers and human reasoning closer together to develop new capabilities to solve important offshore problems especially in harsh environments for humans.
    • Statoil has projected that automation may cut in half the number of workers needed on an offshore rig and help complete jobs 25 percent faster.

In addition to the robotics initiatives specific to onshore and offshore, companies are also working on robotics to perform other important tasks.  Some companies are embedding robot-like intelligence into devices and tools to improve accuracies and enable great maneuverability and performance such as sensors and intelligence in a drilling bit to help direct speed, direction and communications with GPS satellites, networks to make real-time decisions about how to get around obstacles and avoid unwanted events.

Robotics-like drones are being deployed along pipelines with cameras and other sensing devices to enable real-time inspection for leaks and other potential security or HSE violations and even disasters that might occur.   Drones and cameras are estimated to generate high volumes of image data that will flow across the oil field to be analyzed especially along pipelines to detect pipe leaks and other security and compliance-related issues preferably before they occur.

IDC forecasts the following for the future with regards to robotics in oil and gas:

  • By 2018, the average selling price of an industrial robot will be one fifth of what it is today, but have 5 times the capability!
  • By 2016, 80% of market potential is untapped due to safety and privacy concerns
  • By 2018, 30% of drones are not owned, but managed by third parties -accelerating deployments
  • By 2018 50% of underwater submersibles will be unattached, self-propelled and with greater maneuverability, dexterity and task-performing capabilities like welding, inspection, and communications.
  • By 2018 autonomous robotics will appear in the oil field leveraging new sensors, tools and capabilities like; machine vision, force sensing, speech recognition, advanced mechanics
  • By 2020, 50% of supply chain jobs will be eliminated through automation, robotics and the use of new technologies like cognitive computing and robotics

 

As technology evolves, and oil and gas companies strive to achieve operational efficiencies, we should expect more innovations, more cost-effective robotic configurations, and more applications as companies learn how to exploit the value of robotics. The potential is dramatic because soon robots will offer not only improved cost-effectiveness, but also advantages and operations capabilities that have never been possible before.

 

There is a clear incentive for oil and gas companies to automate their oil and gas facilities and activities where appropriate. Investing in robotics and IoT technology is an innovative way to complement the digital transformation strategy to achieve: operational efficiencies, reduce safety risk, access more remote areas, and provide more transparency into remote operations.

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The cleaver, the scalpel, and then, finally, some glue… http://www.oilgasmonitor.com/cleaver-scalpel-finally-glue/ Mon, 01 Aug 2016 06:30:37 +0000 http://www.oilgasmonitor.com/?p=11411 Joe Gibney | Capital One Securities A look at operating model adjustments, M&A, and collaboration within the oilfield equipment manufacturing sector through the industry decline of the past year and a half.   The butcher’s bill for the whole of the oilfield services sector has been extensive in the wake of WTI’s mid $20s bottoming […]

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August 1, 2016
Joe Gibney | Capital One Securities
A look at operating model adjustments, M&A, and collaboration within the oilfield equipment manufacturing sector through the industry decline of the past year and a half.
 
The butcher’s bill for the whole of the oilfield services sector has been extensive in the wake of WTI’s mid $20s bottoming and the resulting CAPEX austerity. With liquidity preservation understandably serving as priority one for E&P customers during the maelstrom, short-cycle activity ground to a standstill and orders – both via capital equipment deferral/cancellation and inventory cannibalization for consumables – dried up completely. The recent WTI recovery to the mid $40s has only just now begun to shake loose an increase in customer inquiries. While the rig count has shown signs of modest uplift with speculation regarding the return of completions work, most operators are still characterizing the inquiry lift as yellow shoots – that is, the phone is ringing more but it’s not yet meaningfully translating into purchase orders or booked jobs.

The butcher’s bill itself is staggering. The U.S. total rig count bottomed 77% from peak levels in the fourth quarter of 2014. The international total rig count is down 33% and still declining. The global contracted offshore floating rig count is down 36%. Fifty-eight floaters have been retired since October 2014 (equivalent to the amount retired over the last 30 years). Full year 2015 industry-wide subsea tree orders were down 34% year over year, following 58% declines in 2014. National Oilwell Varco’s (NYSE:NOV) Rig Systems orders have averaged $93 million over the last two quarters versus $2.6 billion per quarter at the peak.

This is where the industry began using the cleaver, as its initial operating response was blunt force trauma, attempting to match headcount reductions and facility closures with the plummeting drilling activity. General and administrative spending trends from peak 2014 levels serve as a reasonable proxy for this cleaving, with average reductions across our covered OEM universe around 35%. NOV alone has closed more than 200 facilities, and every operator has looked at ways to re-trench into core facilities, insource machining hours, move to single shifts, and reduce wages.

As the velocity of the activity and order declines slowed, however, we began to see operators put down the cleaver and pick up the scalpel. This has been a more challenging and nuanced exercise that involves ascertaining what level of forward capacity is appropriate and trying to balance the last 18 months of acute cost control against the need to preserve the ability to participate in the inevitable upcycle. On the short-cycle side, this is more of a near-term geographic positioning exercise with restructuring of management and service-line consolidation shifting to a desire to keep field personnel and positioning them in basins likeliest to see the most near-term improvement. How much incremental activity can be absorbed by this level of field personnel is an oft-discussed topic but most operators seem confident they can absorb an activity rebound back to more than 800 rigs in the United States without adding much in terms of incremental cost other than logistics, transport, and overtime. This is a balancing act that pales in comparison to longer-term structural planning on the manufacturing capacity front.

Instilling lean initiatives and de-layering organizations in order to deliver sustainable cost reductions are the main drivers of the ongoing scalpel moves within the OEM space. Standardization of processes (machining, assembly, testing) enables consolidation into fewer locations and greater efficiency. These initiatives are underway within FTI’s Subsea division, within NOV Rig Systems, and across the board for all OEMs with a global footprint. Forum Energy Technologies (NYSE:FET) set a goal to consolidate global manufacturing and distribution facilities by 20% without sacrificing capacity. This consolidation, along with procurement initiatives, is driving a targeted $100 million improvement in cost structure that is expected to increase margins in a recovery scenario by 500 basis points. Some costs are inevitably going to rise with an upturn but these scalpel initiatives should enable a core of permanent cost reductions that should lead to healthier incremental margins in the upturn.

A cyclical recalibration of this magnitude requires putting everything on the table and rethinking prior accepted processes, considering out-of-the-box thinking to grow share in a smaller opportunity pool, and working with customers to realize the needed cost reductions that will lead to acceptable project economics. Overhead and price reductions only go so far – fundamental changes in development approach are also required. This is where the strategy through the downturn shifts to the glue, as collaboration, consolidation, and M&A now begin to coalesce.

The genesis of this thinking can be seen in the August 2015 Cameron-Schlumberger merger (following their OneSubsea JV which became operational in June 2013). Some aspects of this transaction were hard to reconcile: a greater than 56% premium and marrying a service provider with a manufacturer seemed incongruous in terms of culture and process, and CAM’s drilling franchise was (and is) an overhang given order/throughput challenges. However, in an effort to achieve total well cost savings with better integration of equipment and service, SLB had already progressed from reservoir characterization to downhole tool and rotary steerables integration, SII/M-I bits, and fluids, leading to a fully integrated downhole system along with tucking in select completion hardware into the service offering. With a target of $600 million in synergies and a “pore-to-pipeline” emphasis on product and service deliverability, CAM carries this progression to its next iteration – marrying downhole/reservoir expertise with manufacturing process/installed base, overlaid with instrumentation/automation to create an end-to-end product-service concept with significant scale synergies.

The FTI-Technip collaboration via the Forsys JV (announced March 2015) that progressed to a full company combination (announced May 2016) provides another collaborative example. Similar to CAM-SLB, questions arose: a long wait on $400 million cost synergy realization, uncertain customer embrace of the EPIC/integrated approach, and how onshore will benefit from the integration beyond a more bundled product/service sales approach. Despite these questions, the original intention of Forsys remains: demonstrate that early involvement in the FEED stage, standardization of products and interfaces, technology sharing, and end-to-end coordination of subsea production systems and subsea installation (which constitute approximately 1/3 of offshore total well costs) can result in meaningful cost reductions of more than 25%.

In July 2016, NOV and GE Oil & Gas also furthered the collaborative agenda with the announcement of an agreement to jointly develop FPSO solutions. This brings together NOV’s product positioning on turret mooring systems, flexible risers/flowlines, composite piping, cranes, and fluids pumping & treatment with GE’s positioning in topsides power gen and compression. It’s been slow going on the FPSO front, as NOV has built its product suite via a series of acquisitions, primarily APL, Prosafe, and NKT going back to 2010 with the aim to create a standardized FPSO kit similar to a deepwater rig package. The company remains involved with several FEEDs, bidding both separate turret/mooring systems along with a full standardized package. Marrying up the power gen/compression piece of GE completes the full topsides package and, with standardization of interfaces and supply chain efficiencies, can now more meaningfully drive reduced costs.

The final application of glue will inevitably center on a return to bolt-on M&A. Bid-ask spreads have understandably been misaligned for the last 18 months, as all prospective deal-making parties have been searching for the bottom and some sense of the pace of initial recovery. M&A historically begins to pick up as activity inflects off the bottom and we are now only in the nascent stages, as the free cash flow and liquidity survivors of the space look to expand product portfolios and market share.

While smaller in scale, the recent NOW Inc. (NYSE:DNOW) acquisition of Power Services (finalized June 2016) demonstrates an effective combination of innovative thinking coupled with market share-driven, bolt-on intent. The acquisition bolsters valve content with spooling and modification capabilities and more meaningfully pushes DNOW outside its distributor core and into fabrication with Power Services’ modularized tank battery solutions. This provides DNOW with a more competitive turnkey solution to well completion sites and potentially serves as a differentiator to garner market share in a smaller North America upstream opportunity set.

It’s been a challenging 18 months for the industry, with the velocity of commodity and activity declines making this cyclical downturn one of the most severe in history. But with the cleaving behind us, select scalpel work being finished up, and the first signs of meaningful glue being applied, we’re all looking forward to hopefully better days ahead as a new upturn inevitably begins to coalesce.

Disclosure:

Securities products and services are offered through Capital One Securities, Inc., a non-bank affiliate of Capital One, N.A., a wholly-owned subsidiary of Capital One Financial Corporation and a member of FINRA and SIPC. The products and services offered or recommended are: Not insured by the FDIC; Not bank guaranteed; Not a deposit or obligation of Capital One; May lose value.

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Bridging the IIoT gap: How Information Technology (IT) and Operational Technology (OT) can Work Together http://www.oilgasmonitor.com/bridging-iiot-gap-information-technology-operational-technology-ot-can-work-together/ Fri, 29 Jul 2016 06:19:21 +0000 http://www.oilgasmonitor.com/?p=11401 John Fryer | Stratus Technologies As companies across the energy value chain look for ways to become more efficient and agile, the Industrial “Internet of Things” (IIoT) offers attractive opportunities. Harnessing sensor data, machine-to-machine (M2M) communication and Big Data analytics enables oil and gas companies to take automation and efficiency to new heights, while creating […]

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July 29, 2016
John Fryer | Stratus Technologies
As companies across the energy value chain look for ways to become more efficient and agile, the Industrial “Internet of Things” (IIoT) offers attractive opportunities. Harnessing sensor data, machine-to-machine (M2M) communication and Big Data analytics enables oil and gas companies to take automation and efficiency to new heights, while creating the foundation for new business models.

But to realize the potential of IIoT, companies must first bridge a yawning gap: the technological and cultural divide that often separates their information technology (IT) and operational technology (OT) organizations.

Why the divide? In most industrial organizations, including oil and gas producers, IT and OT traditionally have different priorities. For OT, ensuring the uptime of production automation systems is paramount. Reducing risk is the top priority, which is one reason why automation systems are often in service for years, if not decades—change equals risk. For IT, innovation is the top priority, often leading to continual change and upgrading. This difference in priorities helps explain why OT often insists on keeping automation systems completely isolated from IT.

The IIoT changes the status quo, creating a new imperative to share data from machine sensors and automation systems managed by OT—including SCADA (Supervisory Control And Data Acquisition) systems—with enterprise resource planning (ERP) systems and analytics platforms managed by IT. How can oil and gas companies bridge the gap between these two worlds, while ensuring that the competing priorities of OT and IT are met?

Three approaches

One approach employed by some energy companies is to effectively merge the two, integrating OT within the IT group. On the surface, this seems like the most straightforward approach, essentially forcing OT and IT to work in coordination. In practice, however, the cultural differences can remain. For example, IT may try to impose its standards-based approach on an OT team used to systems specialized for particular production tasks. Unless IT has a clear understanding of the requirements of these automation systems, the result can be a lack of coordination that decreases system stability. For this approach to work, OT must have a voice in the combined organization.

Another approach is to create a technology team free from these traditional distinctions, responsible for all OT and IT functions. This approach is feasible in an entirely new organization or for a large company spinning off a new satellite organization. But for most large, complex oil and gas producers with established technology groups and lots of legacy infrastructure, it may not be a workable alternative.

The third approach is one we’re seeing more and more in forward-looking organizations, where there is a new breed of “industrial technologists” who have a combined IT/OT perspective. They understand the need for stable, highly available automation systems, but they also understand the enterprise system integration and analytics required to make the IIoT a reality. With a foot in both worlds, these industrial technologists play a key role in ensuring that the priorities of both OT and IT are met.

Showing OT the value

Overcoming the cultural divide between OT and IT will likely be a gradual process for many organizations. A key step in facilitating that process is showing the OT team the value of the IIoT and of “opening the door” to their automation systems and data.
For example, gas gathering operations could turn the manual, inaccurate process of reconciling the production imbalance sheet into a remotely automated process, laying fiber or using wireless, to all of their remote facilities to relay sensor data to a centralized analytics system. This can allow them to access accurate imbalance sheet data for all production sources in near real time, without tying up valuable staff time.

Another example near and dear to OT is that of predictive maintenance. Sensor data for a range of operational parameters can be collected for individual equipment components and sent to analytics engines or machine learning systems to detect anomalies—such as vibration patterns on compression turbines or temperature excursions on a motor—before a failure occurs. This can reduce unplanned downtime, the bane of OT, while also helping identify the optimum maintenance or replacement intervals, minimizing costly planned downtime and capital expense.

Reducing the risk of change

A critical success factor when merging OT and IT functions is effectively managing risk. OT must be assured that SCADA systems and data will maintain the highest levels of availability. That means building in fault tolerance for all mission-critical systems linked to production.

Availability is especially critical given the cost pressures the industry is under today. With technology staffs cut to the bone, it is essential to ensure that automation systems at remote locations—such as compression stations, well locations and storage facilities—stay up and running. If someone has to travel to the location to deal with an outage, production could be impacted for days. Moreover, building in availability helps avoid the inevitable finger-pointing between OT and IT if an outage were to occur in a converged IIoT infrastructure.

The benefits of the IIoT are too attractive not to take advantage of them. Bringing OT and IT together in a way that effectively manages risk is the key to unlocking the tremendous potential of the intelligent, automated energy enterprise.

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Artificial Intelligence in Upstream Oil and Gas http://www.oilgasmonitor.com/artificial-intelligence-upstream-oil-gas/ Fri, 24 Jun 2016 06:32:00 +0000 http://www.oilgasmonitor.com/?p=11380 Dr. Arunkumar Ranganathan | Infosys Increased use of machine learning technology is driving growth in artificial intelligence (AI) adoption. By 2020, it is estimated the market will be worth over $5 billion. Oil and gas is one of the key industries expected to reap rewards from AI, though adoption is slow compared to other sectors. […]

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June 24, 2016
Dr. Arunkumar Ranganathan | Infosys
Increased use of machine learning technology is driving growth in artificial intelligence (AI) adoption. By 2020, it is estimated the market will be worth over $5 billion. Oil and gas is one of the key industries expected to reap rewards from AI, though adoption is slow compared to other sectors.

The energy exploration sector is acutely aware of the need to identify new assets for exploration while increasing production at existing oil and gas fields. Crucially, companies must ensure the safety of personnel on sites and protect the environment at all times. Increasingly, manual processes are proving unsuitable in the field, but advanced technology solutions such as AI can support growth and eliminate health and safety issues to a large extent.

Oil is found in the minds of men

Risky as it may be, successful exploration requires a combination of visionary theory, technical innovation and commitment – and a bit of luck to be in the right place at the right time.

Geoscientists have the knowledge and experience to locate reserves. As resources become more scarce, AI systems hold the key to pinpointing new drilling sites. Geoscientists retain a wealth of information and asset knowledge but transferring this expertise to the wider organization, and the industry, is ineffective. AI systems play a crucial role in enabling scientists and engineers to remain productive irrespective of their experience.

AI offers a robust data interpretation process that can assist with critical knowledge transfer and decision making. It enables higher productivity and creates opportunities for advancement. While AI has been in use in the upstream lifecycle over the last two decades, there remains a skeptical belief amongst traditionalists that there is no better substitute for the human brain.

Applying AI in the exploration and production (E&P) life cycle

AI system consists of various tools: machine learning, fuzzy logic, artificial neutral networks, and expert systems. These systems transform data into valuable insight that can be applied across various stages of the E&P life cycle, including seismic, geology, drilling, petrophysics, reservoir and production.

Regardless of the business maturity level, AI systems have the ability to automate and optimize data-rich processes. They eliminate duplication of effort and mitigate business risks. As a result, they enhance productivity and minimise the cost of operation. Organizations that have reengineered their strategy and operational models to include AI elements have seen a positive business transform across the enterprise. Use of AI systems will remove redundancy, reducing the cost per barrel.

AI adoption begins with machine learning

Machine learning techniques in oil & gas will require deep insights into the process which it is designed to supports. For example, seismic processing requires the design of various data filtering techniques to enhance signal to noise ratio. These are used in both forward and inverse modeling. By adjusting the parameters within the learning sets and iterative routines, geoscientists can quickly eliminate repeatable procedures and apply this to real-time data for faster feedback.

Establishing processing parameters is an iterative process that improves accuracy. Geological modeling that relies on data alone is meaningless unless the geologist can apply their knowledge to refine the model. For example, the Kriging method is used to interpolate geological models between wells, which helps to refine the process by analyzing additional data input such as seismic lines, well log data, core and cuttings data.

The use of AI techniques helps ensure the process is repeatable in a consistent fashion, as well as enabling the automation of the actual physical task, freeing up staff resource. It also helps preserve the integrity of the analysis even if the geoscientist fails to acquire data in new wells.

Once the foundation is set, fuzzy logic systems can then be applied to support petroleum engineering processes including petrophysics, reservoir characterization, enhanced recovery, infill drilling and well simulation.

Eliminate costly risks in drilling

Drilling is a highly expensive and risky investment. Applying AI in the operational planning and execution stages significantly improves the success rate across the various stages of drilling including: well planning, real-time drilling optimization, estimating fictional drag, and well cleaning prediction. Additionally, geoscientists can better assess variables such as the rate of penetration (ROP) improvement, well integrity, operational troubleshooting, drilling equipment condition recognition, real-time drilling risk recognition, and procedural decision making.

AI techniques can also be applied in other activities such as reservoir characterization, modeling and field surveillance. Fuzzy logic, artificial neural networks and expert systems are used extensively across the industry to accurately characterize reservoirs in order to attain optimum production level.

Today, AI systems form the backbone of digital oil field (DOF) concepts and implementations. However, there is still a lot of scope to develop new techniques to optimize field development and production costs, prolong field life and increase the recovery factor.

Gaining popularity

AI techniques are most commonly applied in processing and interpreting well log data. In determining the parameters for multi-well processes, facies analysis is performed using quality reservoir data according to the number of wells covering the entire reservoir section. This process involves patter recognition, semi-supervised clustering and grouping.

The data interpretation highlights important geological features such as faults, folds, unconformity and boundaries. This information provided by the AI system is crucial because geoscientists sometimes fail to acquire this critical insight due to poor well conditions and other external factors.

AI techniques enable field experts to automate the system using available data to generate pseudo open whole logs in new wells, either using the Monte Carlo method or case hole logs. Training the system and feeding in well data will enable geoscientists to obtain more accurate log systems.

The use of AI in the oil and gas industry is gaining popularity but overall adoption remains relatively low compared to other sectors. There are plenty of opportunities to develop AI systems to further optimize, automate and improve business and operational efficiencies. Combined with the use of data analytics, there is much value to be gain in the AI market that industry leaders are yet to explore.

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Hydraulic Fracturing and the Water Environment http://www.oilgasmonitor.com/hydraulic-fracturing-water-environment/ Wed, 22 Jun 2016 06:26:38 +0000 http://www.oilgasmonitor.com/?p=11369 Jeanette Brown | Manhattan College Hydraulic fracturing to obtain oil and natural gas has had a very positive impact on making the United States energy independent.  However, there are water related issues associated with the hydraulic fracturing process such as: water withdrawals; groundwater contamination associated with well drilling and production; wastewater management; truck traffic and […]

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June 22, 2016
Jeanette Brown | Manhattan College
Hydraulic fracturing to obtain oil and natural gas has had a very positive impact on making the United States energy independent.  However, there are water related issues associated with the hydraulic fracturing process such as: water withdrawals; groundwater contamination associated with well drilling and production; wastewater management; truck traffic and its impacts on water quality; surface spills and leaks; and stormwater management.  Two of the most critical issues are water withdrawals and wastewater management.

Water Withdrawals:  Each wellhead requires about one million gallons of fresh water for the fracking process. This results in many billions of gallons of water being used every year. For example, just the Bakken Shale play in Eastern Montana and Western North Dakota alone used approximately six billion gallons of fresh water during 2013.  Many of the shale gas plays are in water stressed regions of the United States where the use of water for fracking is competing with water needs for food production (agriculture and ranching), such as in the Eagle Ford, Barnett Shale, and Permian Basin plays in Texas.  With either insufficient river water supplies or regulatory restrictions, some fracking operations are now purchasing water from private sources, thus increasing costs. For example, the Army Corps of Engineers recently mandated against withdrawing water from the Missouri River for use by fracking operations so operators in those regions must find other sources of fresh water.  Even in water rich areas such as Pennsylvania, there are concerns about water use and the impact on drinking water sources.  The Susquehanna River Basin Commission has stated that the Marcellus Shale play can use up to eight million gallons of water in a single week as the number of wells increase.    Although the volume of water being withdrawn seems extremely large, it is relatively small when compared to the amount of water being used and consumed annually.  According to US-EPA, about 44 billion gallons of water were withdrawn for fracking operations during the period from 2011 to 2012, but this represented only about 1% of the total annual water use and consumption for that same period. However, water withdrawals can result in high competition for water and increased potential for conflicts among various stakeholders in certain locations.

Wastewater Management:  Wastewater generated from the wells is also a major problem.  Flowback from the well typically represents about 60% of the water initially injected into the well and in addition, each well can produce as much as 100,000 gallons per day of wastewater during its operation.   This wastewater must be stored, treated, or disposed of in some way.   Fracking wastewater tends to be high in salinity (represented as total dissolved solids-TDS) and can contain metals and natural occurring radionuclides.  In addition, it contains chemical additives that make up the fracking fluid and excess proppant, as well as residual petroleum products.  As noted by US-EPA, since these constituents are not typical of municipal influent wastewater, fracking wastewater disposed at a municipal treatment plant can be discharged, untreated to surface waters, can disrupt the operation of the treatment plant (for example, by inhibiting biological treatment), can accumulate in biosolids (sewage sludge) limiting their use, and can facilitate the formation of harmful disinfection by-products. In addition, many of the chemicals used in fracking fluids are unknown making it difficult to assess the fate of these chemical through a municipal treatment plant, their impact on water quality of the receiving water, and their potential impact on drinking water sources.  Municipal treatment plant operators are reluctant to allow fracking wastewater to be discharged to their facilities so fracking wastewater is typically disposed of by deep well injection, centralized treatment facilities, and/or reused by the fracking operations.

Although deep well injection is a common way of disposal, it can also result in environmental problems with potential contamination of groundwater as a drinking water source.  In some areas there are insufficient deep wells available resulting in wastewater being transported long distances for deep well injection at other locations.  For example, some fracking companies in Pennsylvania ship wastewater to deep well injections sites in Ohio with trucks driving several hundreds of miles to these sites.

Centralized wastewater treatment (CWT) plants are facilities designed to remove many of the components in the fracking wastewater. The effluent from these treatment facilities can be sent to a municipal wastewater facility for further treatment, or reused by the well operators.  According to an EPA report, the use of CWTs for hydraulic fracturing wastewater is greater in the Marcellus Shale region than other parts of the country most likely due to the lack of deep well injection sites and the high cost of trucking water for disposal. However, these CWTs cannot remove TDS so any effluent that is not reused cannot be discharged to surface water without further treatment.  The amount of water reused by fracking operators varies by location with about 70 to 90% being reused in the Marcellus Shield and little to none in Bakken Shield in North Dakota no water is reused.

Hydraulic fracturing has played a major role in making the US energy independent and providing more economical energy.  The issues associated with water withdrawal and wastewater treatment are solvable issues.  There are many research projects currently underway to developing solutions.   It is important that there is open communication and cooperation between fracking operators, companies producing fracking additives, and researchers so that the most efficient treatment technology is developed to ensure that fracking wastewater can be entirely reused.  Additionally, studies must continue to identify both short-term and long-term environmental risks and impact on drinking water quality and quantity allowing for the development of methods to mitigate these risks.

 

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Downhole Water Detection and Measurement – Not a One-Size-Fits-All Process http://www.oilgasmonitor.com/downhole-water-detection-measurement-not-one-size-fits-process/ Mon, 20 Jun 2016 17:11:39 +0000 http://www.oilgasmonitor.com/?p=11362 Frances Metcalfe | Cambridge Consultants Water is a significant by-product of the production of oil and gas – in some cases, accounting for up to 95% of produced fluids. The resulting reduction in revenues, coupled with the costs of water treatment and safe disposal, can render a well uneconomic – and even stop production altogether. […]

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June 20, 2016
Frances Metcalfe | Cambridge Consultants
Water is a significant by-product of the production of oil and gas – in some cases, accounting for up to 95% of produced fluids. The resulting reduction in revenues, coupled with the costs of water treatment and safe disposal, can render a well uneconomic – and even stop production altogether. But conventional techniques for monitoring the production profile of a well to enable troubleshooting are less effective in the increasing number of horizontal wells. Gaining insights into water production and location of inflows requires a number of trade-offs to be considered spanning accuracy, technology selection, measurement location and of course, cost. So what options are currently available to operators of oil and gas wells and what challenges remain?

The balance of measurement requirements of water production is important. Whilst an accuracy at the wellhead of 0.5% for overall water cut (the % of water in produced fluids) is needed for financial purposes (as the value of oil is much greater than that of water), operators of an oil or gas well need positional information on which reservoir zone is producing water so that mitigating action can be taken, but can trade this off against an accuracy of 5% to 10% water cut from downhole sensors.

So, where to start? To make an informed choice we need to consider the physical constraints and the available technologies.

Just making measurements in this environment presents many challenges requiring a multidisciplinary approach to engineer a good measurement – fluidics, sensor physics and electronics, and mechanical design are all key to allow sufficient sensitivity but also permit a sensor to operate over an extended period (10 years or more for a permanent sensor) in a harsh environment. Sensors must operate under high pressure, high temperature and offer chemical resistance (to H2S for example). Once that challenge is met, we still need to add data analysis and mathematics to extract actionable information from the sensor data. Add to this resilience; failure cannot interfere with production and redundancy will be important for key measurements, requiring rigorous application of reliability engineering.

Wellhead water cut meters are well established and are available from a number of suppliers but don’t provide information about the location of water production, and often represent measurements of co-mingled flows from several wells.

Downhole sensors can offer improved information on the location of a water inflow but introduce additional considerations: size (needing to fit in the confined annular space for example), power and communications requirements, and restrictions of number of and type of cable that can be run downhole and through packers. This is not a significant issue for a single well or lateral, but is much more of a challenge for multi-laterals. Solutions vary from permanent installations to intervention techniques and systems (e.g. wireline conveyed instruments). Ideally, these should offer a measurement of a representative sample of the zone, work for the lifetime of the well, and shouldn’t interfere with production e.g. by intruding into the flow itself.

Sensing and measurement techniques employed can be classified either as direct or indirect measures of water.

Direct measurements involve measuring the material properties of the produced fluid using physical techniques such as optical absorption and other EM or electrical methods (such as conductivity or capacitance). The performance of these can be limited by factors such as optical scattering or distortion of electrical properties due to variations in water salinity.

Indirect methods infer the water content and flow from measures such as downhole temperature and pressure, for example analyzing the outputs from downhole gauges or distributed temperature sensing (DTS) which monitor thermal profiles in a well, and comparing thermal models with the results to infer water inflow from deviations from the expected natural geothermal gradient. This technique becomes less effective as wells approach 90° deviation (horizontal), as there is no longer a geothermal gradient along the sensor path and temperature deviations can be smaller than the resolution of the DTS instrument. Emerging technologies employ chemical tracers that are selectively absorbed by water and oil in the flow; their concentrations in the produced fluids are then measured offline in samples taken at the surface.  These have the advantages of being passive, without need for downhole power and communications, although their lifetime is finite and the techniques are not currently real-time since offline analysis is required.

In conclusion, we can see that downhole water detection is still an evolving area; there is no ‘one-size fits all’ technique, and in particular, multilateral (horizontal) wells present some new challenges. There are opportunities to develop new technologies such as RF measurements to measure differences in physical properties of hydrocarbons and water to determine the composition of fluid flowing past a non-intrusive sensor. In addition, the use of analytical techniques to fuse results from emerging and existing measurements offers the potential to address these important challenges and enable operators to take well-informed and early action to mitigate excess water production.

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Four Ways Management Consultants Can Help Oil and Gas Companies Look to the Future http://www.oilgasmonitor.com/three-questions-ask-cmo-standard-operating-procedures/ Fri, 27 May 2016 06:49:22 +0000 http://www.oilgasmonitor.com/?p=11346 Regina Mayor & Matt Smith | KPMG In today’s “lower for longer” commodity pricing environment, even the best positioned oil and gas companies are experiencing market challenges. Despite these challenges, executives should not lose sight of opportunities to make transformative changes that can help them derive greater value from their businesses. To emerge from this […]

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May 27, 2016
Regina Mayor & Matt Smith | KPMG
In today’s “lower for longer” commodity pricing environment, even the best positioned oil and gas companies are experiencing market challenges. Despite these challenges, executives should not lose sight of opportunities to make transformative changes that can help them derive greater value from their businesses. To emerge from this prolonged scenario stronger than before, executives should look at fortifying areas of their businesses through sustainable cost reduction strategies as well as capital and workforce management. Lower energy prices may leave some of the heavily indebted producers vulnerable as interest payments swallow up cash. Some of those organizations may have little choice but to sell, find partners, or recapitalize themselves, creating a need for advisors to guide them through this. By taking a closer look at the following four areas with the help of management consulting expertise, companies can begin to see value, savings and greater efficiency in their operations, thus allowing them to focus on thriving.

Working Capital Management

To navigate today’s environment, maximizing cash flow is critical and working capital is an important source of short term funds. Management consultants can work side-by-side with company leaders to look at short-term liquidity difficulties and put a long-term restructuring plan in place that releases working capital to stabilize operations and fund growth or expansion. Some key sources of working capital for companies to identify include:

  • Bill-to-Cash system improvements
  • Efficient handling of how many days sales are outstanding, credit management and settlements and dispute resolution
  • Forecast-to-Fulfill process (Inventory) optimization
  • Elimination of excess work in progress (WIPs), obsolete spare parts and poor alignment between planning and operations
  • Management of risk to achieve the appropriate balance in the business between profits, revenues and working capital
  • Realizing tax savings across business units and the enterprise

There are no silver bullets to effective working capital management and companies need to employ a tested methodology with reliable benchmarks on expected savings. This is frequently an area where a “gain-share” fee arrangement can increase the likelihood of a significant return on consulting spend.   The benefits to a successful program include an improvement in cash management, greater clarity over the short and long term cash needs and the development of liquidity strategies to respond to changes in market.

Supply Chain Finance & Materials Management

In the current environment, tension between buyers and suppliers around payment terms continues to intensify. In the U.S., payment cycles typically range from 55 to 60 days; however, the best-in-class industry standard timeframe to approve electronic invoices averages 10 days. This discrepancy creates a significant cash flow opportunity for companies – particularly as strict bank lending requirements are impairing suppliers’ abilities to secure sufficient capital to fund operations. There is tremendous potential from both a margin and a working capital perspective with a successful supplier finance program supported by technology that enables dynamic discounting and e-invoicing. The key activities associated with developing a successful supplier finance program and technology solution include:

  • Business case development and tracking, which includes conducting a spend analysis, supplier segmentation, benchmarking, and developing business case KPIs.
  • Value/Supplier enablement, which entails developing supplier enablement and communication strategies, supplier onboarding and invoice to pay (I2P) optimization.
  • Technical implementation services such as business requirements gathering, project management, technical configuration, and integration and acceptance testing.
  • Change management activities including cross functional alignment, stakeholder analysis, training, and employee and supplier engagement.

Enterprise Asset Management

Oil and gas companies need to invest where they can get the greatest return and defer investments in assets that do not cover their costs in a market with low energy prices.  Developing an enterprise asset management (EAM) program can enable management to improve the return on an asset by optimizing costs associated with operating, maintaining, buying, replacing, and disposing of capital assets. This activity typically represents 25 to 38 percent of operating costs. With the assistance of management consulting, key stakeholders within oil and gas companies (i.e. network engineering, construction management, finance, tax, supply chain, etc.) can come together to create an effective EAM framework that standardizes key processes across regions and business units. The following steps will allow for a successful EAM initiative:

  1. Develop Strategic Framework – Align business methodologies with asset management priorities, long-term objectives, KPIs, and a constraints management plan.
  2. Asset Analytics – Develop asset risk models and a long-term asset investment strategy aligned with baseline plans for maintenance, refurbishment and replacement of assets. Part of this is setting return on investment targets and measuring them against the cost of capital.
  3. Decision Execution – Execute capital and operations/maintenance decisions supported by business cases.
  4. Ongoing Performance Management – Enable continuous improvement cycle and variance analysis including identification of trends, gaps and documentation of corrective actions.

Companies that can effectively integrate people, processes, applications, and data allow for enterprise asset management to achieve the desired cost savings and operating efficiencies.

Sourcing Strategies

Many corporate functions including IT, finance and accounting (F&A), HR, SC, and facilities management include activities that can be delivered as a managed service at a lower cost than an internal service delivery model. This allows the organization to focus on its core competencies, such as exploration and producing energy. Cost savings ranging from 15 to 35 percent can be derived from lower labor costs (especially in an offshore model), scale, consistent business processes, efficient utilization of technology and properly aligning work with required skills.  Some firms are also using cognitive engines and robotics to automate manual work activities.  A successful outsourcing strategy needs to be carefully designed with ample consideration of the appropriate scope of work to be sourced versus retained internally and the desired service levels to be contracted.  Transition activities also present risks that need to be carefully managed and the relationship with third party service providers need appropriate governance to deliver sustainable cost savings.

Oil and gas companies that take the opportunity to focus on these four areas will be able to devote the appropriate resources to navigating the current commodity pricing environment to generate the most value. The assistance of management consultants can guide energy companies to help company leadership to identify priorities for their businesses, develop plans to accomplish short and long-term goals and manage the process through to completion, regardless of the direction of energy markets.


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From Assessment to Action: Extending the Role of Management Consultants in Oil & Gas http://www.oilgasmonitor.com/assessment-action-extending-role-management-consultants-oil-gas/ Mon, 16 May 2016 06:00:34 +0000 http://www.oilgasmonitor.com/?p=11334 Jennifer Schwartz | CTG Whether it’s the need for manpower, cost savings, or an outside perspective, the impetus behind companies bringing in consultants is obvious – they’re looking for that competitive edge. One way to do that is to gain insight from the oil and gas industry’s heavy hitters. These experts are valuable because they […]

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May 16, 2016
Jennifer Schwartz | CTG
Whether it’s the need for manpower, cost savings, or an outside perspective, the impetus behind companies bringing in consultants is obvious – they’re looking for that competitive edge. One way to do that is to gain insight from the oil and gas industry’s heavy hitters. These experts are valuable because they bring a fresh pair of eyes to each environment. Often, they also offer a more holistic viewpoint of the industry, having likely worked across numerous companies and in varying capacities. This broad, outsider opinion helps consultants recognize ailing processes and recommend paths that allow companies to improve them. Something puzzling, however, is that a consultant’s job typically ends once the strategy is established or the assessment stage is complete.  How much more value could be realized if consultants saw their plans come to fruition.

For the company, it can be problematic to see the relationship end before the plans are put into motion; it seems logical that having the engineers of the plan assist with executing the changes would produce certain benefits. Consultants would also undoubtedly benefit from seeing their plans utilized. It would help them see what works, what doesn’t and refine suggestions for the future. Undoubtedly, it would make more sense for both parties to extend the relationship beyond simply assessment and planning.

This begs the question: why aren’t these experts being utilized to their full potential?

There’s Always Room for Improvement

Consultants possess unique knowledge and skill sets.  These assets help consultants overcome the challenge of recognizing and adapting to the variances in each client’s environment and problem space. They use their expertise to identify client advantage areas and develop actionable best practices that will improve deficient company processes.

This is a group that can’t take a one-and-done approach. If the overall goal is to provide plans that are actionable, in consideration of the environment in which they will be executed, the plans can only improve as more is learned about the way those plans unfold. For example, in an industry like oil and gas that relies heavily on a contract workforce, cross discipline communication on efforts such as turnarounds is critical.  Operators, inspectors, maintenance staff and discipline engineers need actionable and realistic plans that establish or improve clear channels of collaboration to advance productivity.  Knowing how a plan either hits or misses with each of these groups will help drive improvements the next time a turnaround needs to be executed.  Finding ways for clients to continuously improve is an area of value consultants can bring, as long as lessons are shared and learned.

It seems logical that if a consultant develops a plan to help engineers, operators and contractors work more efficiently together, they should be involved in putting that plan into motion. By doing so, they can witness first hand whether or not their strategy worked and adjust future plans accordingly. Being involved in the end-to-end process is essential to creating a more informed and skilled professional, not to mention a higher efficiency company.

Looking Ahead

Increasingly, companies are recognizing the importance of having consultants that stay involved beyond the initial phase of process assessment. It’s safe to say that down the line we’ll see consultants who are more crucial to processes such as team building, change management, and benefit realization. They will become more responsible for the integration and management of the very changes they outlined, and for making sure those changes deliver the value intended when brought in.

Ultimately, extending the role of consultancy is a positive thing for the industry. By making consultants instrumental in realizing their own strategies, the industry will have access to a more informed, adaptable, and skilled workforce – both in terms of consultants and full-time employees. While it may cost more in the short-term to have lengthier contracts with consultants, this process will ultimately lead to more streamlined, efficient projects and processes, making the extra time, cost, and effort well worth it.

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