Exploration – 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=4.6.9 E&P: Will Production Resilience Continue in 2016? http://www.oilgasmonitor.com/ep-will-production-resilience-continue-in-2016/ Wed, 10 Feb 2016 13:00:19 +0000 http://www.oilgasmonitor.com/?p=10921 Richard Tullis & Brian Velie|Capital One Securities E&P Companies Did More With Less In 2015 The year-long depression in oil and natural gas prices helped spur continued innovation in the energy space in 2015. E&P companies drove down well costs and operational expenses to deliver wells that remained economic, with far lower pricing, than imagined […]

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February 10, 2016
Richard Tullis & Brian Velie|Capital One Securities
E&P Companies Did More With Less In 2015

The year-long depression in oil and natural gas prices helped spur continued innovation in the energy space in 2015. E&P companies drove down well costs and operational expenses to deliver wells that remained economic, with far lower pricing, than imagined possible heading into last year. Industrywide, horizontal well costs declined by as much as 35 percent by late 2015 (vs. mid-2014) while lease operating costs were down more than 10 percent for many U.S. E&P operators.

Much of the well cost savings stemmed from lower rates from the service providers, which slashed fees to help maintain market share and keep crews working. However, drilling efficiency improvements were also a meaningful component of the reductions, and these savings will likely stick even in the event that service companies take pricing back up in the future. General and administrative (G&A) costs also fell more than 10 percent for most companies during the year as operators searched for ways to streamline organizations.

Well productivity climbed in several of the most closely watched basins including the Anadarko, Permian and Williston. For instance, NFX was able to improve its average horizontal well 30-day initial production (IP) rates in the STACK play (in the Anadarko Basin) by more than 40 percent to 930boe/d for its 2015 wells online by October, compared to its 2014 STACK well performance. E&P operators reported similar productivity increases industrywide throughout last year. Significant gains were made by using enhanced completions, improved lateral placement and some high-grading of drilling locations.

In the end, the compounding effect of less expensive wells being drilled faster and then producing significantly more than originally forecasted resulted in stubbornly resilient production throughout the year, even as commodity pricing remained challenged. In fact, seven Permian & Anadarko Basin-focused producers, which benefitted significantly from multi-STACK targets and increased well productivity, scored among the top ten stock performers in 2015 in our coverage group representing 56 companies.

Our two key takeaways from 2015: 1) The well productivity gains and cost cuts that kept activity and production levels elevated last year represented most of the low hanging fruit. Similarly sized improvements in 2016 should not be expected. 2) In the current commodity price environment, the status of a company’s balance sheet has supplanted production growth and now rivals even asset quality as one of the most important considerations behind investment decisions. Case in point: the bottom 10 companies in our coverage list based on 2015 stock performance have an average estimated 2016 net debt/EBITDA of about 8.0x. On the other hand, the top 10 performers in 2015 have an average estimated net debt/EBITDA of about 1.7x in 2016.

Why 2016 Will Be Different

Looking ahead, 2016 could be a critical turning point for the E&P sector, as production is finally likely to begin to decline in the second half of the year. We expect combined 2015 production for the group to be up seven percent vs. 2014 after year-end ‘15 numbers roll in over the next couple of months. In 2016, we are currently modeling full-year production totals to be flat vs. 2015. However, we expect year-end ’16 exit rates to show a decline vs. the 2015 exit.

There are a number of reasons why the production response lags the price declines that first appeared toward the end of 2014. First, the substantial hedges that were in place last year allowed operators to continue drilling on the hope that prices would recover before hedges ran out. That clearly has not happened and with hedges covering less production at lower prices in 2016 drilling activity will slow. For perspective, companies under coverage averaged roughly 50 percent of oil and 42 percent of gas production hedged in 2015. In 2016, we model average hedge positions for companies under coverage of 32 percent for oil and 27 percent for gas production.

Next, while some of the best acreage is economic at even today’s prices, operators will be reluctant to outspend cash flows to drill up the best inventory for hurdle rate returns.

Finally, beginning with third quarter 2015 reporting, many E&Ps began to set the expectation that CAPEX spending will closely mirror cash flows next year. We suspect that theme to continue as budgets are formalized in the coming months. For perspective, the average CAPEX budget for our coverage universe last year was 190 percent of cash flows. Based on initial company commentary, we model 2016 CAPEX budgets to average just 112 percent of cash flows for the year and expect that number to further decline. For our group that represents a 25 percent capital spending reduction (from $75B to $55B) year over year.

The production response from U.S. E&Ps is taking some time but it is inevitable. Last year’s innovations, hedge protection and drilled but uncompleted well inventories have postponed the slowdown, but massive drops in investment coupled with natural well declines will likely begin to catch up by the back half of this year.

Aside from potential macro events like slower growth in China or geo-political tensions in the Middle East, we view onshore U.S. production declines as the most significant signal for the onset of improving oil and gas prices. However, the precise timing of that decline is difficult to peg. Therefore, we favor companies with balance sheets that can withstand a challenging 2016 and have the liquidity to stave off any significant production declines of their own through 2017. If 2015 was the year of “stubbornly resilient production,” 2016 may need to be the year for “stubbornly resilient balance sheets.”

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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Need for New Ideas, Even in a Time of Tight Cash http://www.oilgasmonitor.com/need-for-new-ideas-even-in-a-time-of-tight-cash/ Fri, 22 May 2015 06:15:41 +0000 http://www.oilgasmonitor.com/?p=9443 Simon Ede | Berkeley Research Group & Hugh Ebbutt | Independent Consultant The collapse in oil price in the second half of 2014 has brought a sharp cash crunch to the industry. R&D spending in oil and gas rose over the last decade, following prices and as companies have taken on more complex and challenging […]

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May 22, 2015
Simon Ede | Berkeley Research Group & Hugh Ebbutt | Independent Consultant
The collapse in oil price in the second half of 2014 has brought a sharp cash crunch to the industry. R&D spending in oil and gas rose over the last decade, following prices and as companies have taken on more complex and challenging projects. By 2013, leading researchers and developers in the oil and gas sector were spending over $15 billion annually, double that of a decade earlier.

Will oil company technology spending now be sharply cut as it was during the last sustained price collapse at the end of the nineties? That collapse led to a wave of mega mergers and cost cutting. A new wave of mergers (led by Halliburton-Baker Hughes and Shell-BG) may mean more technology projects will be canned. Shell was selling $15 billion of assets, even before its new acquisition, to pay for already significantly reduced capex and to maintain dividends. Like many other majors, it was struggling to grow reserves or production on its own before the price crash.

The UK is home to hundreds of businesses who supply oil and gas producers, as well as to some key global operators and a range of independents. Much expertise and many skilled jobs depend on this investment. As well as technology work in the larger enterprises, there is a strong interaction with academic institutions, mainly in research and in commercialising and applying key technologies. Nearly 200 oil and gas research projects are funded and spread across around 50 university programmes in the UK. In the tighter environment, where will investment in R&D now come from?

Lessons from the past

These cycles have happened before. Finding and development costs fell throughout the 1980s, driven in good part by improvements in technology. During the 1990s as that downward trend flattened, oil companies sought to prioritise investment by measuring the value that would be added by each technology. But this could be problematic in practice. For the majors, technology capabilities had often simply become an enabler, rather than a real source of value. Access is rarely gained by technology alone, it needs technology plus reputation and deal making confidence.

The price crash and the mega merger wave of 1998-2000 led to significant R&D cuts, including the closing of big technology centres, like those of Amoco, Arco, Mobil, Phillips, Texaco and Unocal. Some of this activity was not completely ‘lost’. A lot of technology development shifted to the service companies and their share of total R&D spend rose.

In the 2000s, the larger players steadily rebuilt their R&D investment. Companies shifted away from simply buying technology start-ups to developing their own technology capability in-house again. Integration between disciplines was seen as key to getting more from applying and connecting technologies. Internal and external teams (from leading universities and government labs) worked together. New research areas like biotechnology and then digital technology started rising up the agenda.

Same again?

It’s a different, more fragmented industry now which must confront this downturn. Technology priorities have changed, and some actors are different. Will service companies once again pick up the slack? Many parts of the service sector are under even more intense near-term cost pressure than the operators. They are losing both business volume and margin, as activity has dropped off a cliff. Deepwater rig rates have almost halved. Schlumberger and Weatherford, for example, each have announced reduced budgets and staff cuts in the thousands. More consolidation is likely. This time the service sector is unlikely to pick up so much of the R&D mantle—at least in the near term.

National oil companies and national champions (NOCs) control around 90% of conventional oil resources and 75% of production. Not traditionally at the forefront of R&D, leading NOCs have rapidly grown spending since 2005 (see chart below). By the start of this decade, Petrobras and PetroChina were matching and exceeding the traditional technology heavyweights, like Shell, Schlumberger, Exxon and Total. The NOCs, with different and often longer-term objectives, more driven by the economic and employment needs of their country, may start to play a stronger role in where key technology initiatives are focused. Many NOCs and governments look to Norway’s precedent, where the oil sector now employs around 10% of its workforce, around 20% of the country’s economic activity and nearly half of its export revenue.

R&D Spending by Global Oil and Gas Producers and Service Companies, 2003–2013


Achieving these objectives will come in part through investing in new technology, just as Norway did, for example, with Statoil’s flagship R&D centre in Trondheim and incentives for in-country R&D. This will position some NOCs as creators rather than consumers of technology. Already, Saudi Aramco, Petrobras, Petronas, and the Chinese NOCs have in-house R&D capabilities and academic collaborations. Saudi Aramco is aiming to become a leading creator of energy technology by 2020. Last year, it announced it would triple its R&D spending. It now has two in-country R&D centres and also collaborations in Scotland, the Netherlands, the United States and China. Petrobras in Brazil has long leveraged its own and foreign universities, developed in-country research centres and collaborated with BG, GE, Schlumberger, Baker Hughes and Halliburton in various local R&D entities and capacities to address the challenges of deepwater drilling.

Newer producers, such as Ghana and those in East Africa, will want to follow countries like Trinidad in developing their universities, research capabilities and vocational training in oil and gas disciplines to provide more, better-qualified people to support their industry, especially when they eventually want to operate their own developments and producing fields.

Technology priorities in a fragmented industry

The number of R&D players may be growing, but there remain a number of common themes of cost, risk and productivity for majors and NOCs alike:

  • Costs have eaten significantly into margins over the last few years despite high oil prices. Getting breakeven points down below $40 to $50 per barrel is a priority in higher-cost basins. Drilling and development costs, especially in deep-water locations—from Brazil and Mexico to the Far East—are still prohibitive, and that is causing project deferrals.
  • Improving productivity and recovery of maturing resources in a lower-price environment is also a common theme. As older fields start to mature, there is an increasing need for better reservoir monitoring, modelling and management of flows. Secondary and tertiary recovery, including steam floods, will be of growing importance. Companies have underinvested in enhanced oil recovery (EOR) technology, perhaps because results are less striking and immediate. However, EOR matters greatly to NOCs. Some, like ADNOC in Abu Dhabi, have set ambitious targets for ultimate recoveries as high as 70%, but have yet to gain the wherewithal to achieve that.
  • Average field productivity is now only 60% in some mature areas like the North Sea. The excessive downtime is driven by failing equipment and so unplanned, reactive maintenance to fix or replace it. Sometimes, around 70% to 80% of operating costs are for equipment or services provided by outside contractors. Simplification and standardisation to more Lego-like modules and smarter management of supply chains and inventories could have enormous impact. So too could digital and other technologies.
  • The search for new reserves leads to a common demand to find ways to de-risk new plays and reduce finding costs. In any basin, the spoils go to those who can drill fewer, better-targeted wells while spending less. This means acquiring more-focused seismic data and a capacity to properly integrate data from key technologies. The challenge will be significant in basins that are little explored, hard to reach, and/or hard to develop, such as in China, India, Myanmar, Africa and Latin America. Here there will be need for faster and cheaper approaches, like airborne surveys (for example, airborne gravity gradiometrywhich has been used with success in East Africa), that can reveal key structures in new basins at sufficient resolution to highlight where to focus much more-expensive seismic analysis.
  • The need for diversity of supply at lower cost is also major goal for growing economies short of their own energy resources. For some—as in Asia and Eastern Europe—the cost of imports is an issue, and developing viable alternatives, including shales where possible, could be important. In China and other areas with dry remote basins, another challenge involves finding ways to get shales to flow where water is scarce.

Recognising the impact of technology and technical expertise

Views vary on how long prices will stay low. The current cash crunch may last into 2016. Geopolitical events, business innovation and technical breakthroughs will still happen—even though they may surprise markets. But whichever scenario plays out, more energy will be needed in the future, as more people want better jobs and better lives. Technology will be key. Those companies—whether leading operators, service suppliers or forward-thinking NOCs—that have planned ahead and nurtured a scarce and valuable resource—their key technical people and capabilities—will be in the strongest positions.

Less investment in R&D by traditional players offers a good opportunity for the increasingly capable national champions and their association research and academic institutions to focus on areas they can do something about and, as the Norwegians have, build up their own resources of exportable expertise. The need to better manage reservoirs, drilling and logistics systems—and to waste and pollute much less—may stimulate new thinking from fresh minds to develop more effective ways to supply and make good use of energy.

The views and opinions expressed in this article are those of the authors and do not necessarily reflect the opinions, position, or policy of Berkeley Research Group, LLC or its other employees and affiliates.


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How Technology Can Save the Day for E&P Companies http://www.oilgasmonitor.com/how-technology-can-save-the-day-for-ep-companies/ Wed, 25 Feb 2015 12:00:17 +0000 http://www.oilgasmonitor.com/?p=8948 Richard Slack | Oildex The Current State of Industry Debt   During the decade-long energy boom, U.S. E&P companies worked hard to boost their output substantially which in turn, also increased their debt loads. As the price of oil falls, many E&P companies are finding it difficult to profit on lesser performing wells and maintain […]

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February 25, 2015
Richard Slack | Oildex
The Current State of Industry Debt
During the decade-long energy boom, U.S. E&P companies worked hard to boost their output substantially which in turn, also increased their debt loads. As the price of oil falls, many E&P companies are finding it difficult to profit on lesser performing wells and maintain their debt obligations. This has left most E&P companies attempting to line up billions of dollars in emergency financing ahead of potential rounds of cuts to their revolving loans.

Banks are expected to begin reining in the size of many E&P companies’ revolving loans in the spring, during their biannual borrowing base redetermination.  E&P companies who are currently the worse off, may be looking at a downsizing of their borrowing base by as much as 10-15% if oil prices remain in the $50-$60/bbl range, according to Reuters.  This could mean $20-$38bn worth of cuts to revolving loans, based on the nearly $260bn in high-yield asset based loans that are outstanding in the industry. It’s still early in the cycle and this makes it difficult for many to determine if extra liquidity is needed however, across all industries, proactive companies are the companies that are able to endure during volatile times.

It is important now more than ever that E&P companies make the exploration and implementation of new technologies such as cloud based resources, automated accounting platforms and online productivity tools, a higher priority. These technologies and solutions have the ability to reduce a company’s’ costs, boost their productivity and significantly maximize their efficiencies.

Automated Accounting Tools to Reduce Costs and Boost Productivity

An automated accounting or ePayables tool is an unrivaled technology platform for companies who are seeking ways to reduce costs and boost their productivity. Traditional paper-based invoice processing is expensive. For an average company in 2014, the average cost to manually process a single invoice was $14.21, according to Ardent Partners. With many E&P companies processing nearly 1,500 invoices per month, the cost associated with paper processing has the potential to severely impact the bottom line. By automating the process, costs can be brought down nearly 70%.

In addition, by streamlining the coding, routing and approving process of supplier invoices, E&P companies can establish digital visibility into their cash flow status. Visibility allows companies to be strategic in their payment process, make better informed financial decisions, and identify the most profitable areas for growth. Automated accounting tools also enable more sophisticated analytics which allow for enhanced insight to better manage business cycles.

Not only is traditional paper-based invoice processing expensive, but it is also vastly inefficient.  Oftentimes manual processes result in payment errors, duplicate payments, and mismatched invoice data, due to the number of steps and individuals it takes to process an invoice. Those errors can further drive up costs and cause delays throughout an organization.  Adopting a streamlined digital process frees up time for busy teams and allows them to focus on higher level tasks that help to develop a company.

Online Business Productivity Tools to Maximize Efficiency

There is a wide range of business productivity tools and apps that E&P companies are able to consider.  Examples include HipChat, a direct messenger communication tool that allows individuals within the organization to connect instantly rather than relying on phones and email and Producteev, which offers powerful task and team management capabilities. Using technology to maximize your business productivity allows a company to realize true business success. Business productivity tools ensure organizations have the capabilities needed to overcome the challenges and issues that arise during strategy execution while boosting efficiency and productivity substantially. Each of these elements is equally vital with E&P companies battling to remain competitive in this volatile marketplace.

Communication based productivity technology tools allow for the automation of processes that provide for faster strategy communication and result in greater project completion rates. With task and team management business productivity tools, companies can more easily communicate business strategy and create measurable goals for their employees that will support overall company objectives. Additionally, these tools allow for greater visibility, enabling employees to see the whole picture and understand more clearly how individual goals fit into the company’s broader business objectives. This creates an engaged workforce which in turn, raises the business productivity of the company.

Moving IT Infrastructure to the Cloud to Modernize & Reduce Costs

Cloud technology is a model for delivering IT services in which resources are retrieved from the internet through web-based tools and applications, rather than a direct connection to a server. This technology has the ability to help E&P companies easily modernize and scale while significantly reducing costs.

Over the past decade, the way E&P companies operate has changed significantly. Despite this change, most production companies still rely on traditional network access from a data center. Enterprise software and applications require servers, bandwidth, networks, data storage, power, and a place to house components. Large E&P companies may have multiple datacenters with several environments for both backup and development work. Adding to this, IT staff and support are also required for maintenance. This can become a significantly complex and costly undertaking.

The oil and gas industry has always required data, high performance computing and collaboration tools and making a switch to a cloud-based data center can decrease the cost of network access substantially. For some E&P companies, it will make sense to explore the crossover to a cloud based IT infrastructure to substantially reduce both complexity and cost.

It’s clear that this will be a challenging year for all professionals and companies within the oil and gas industry.  However, by exploring and implementing smart technologies designed for workplace innovation and modernization, E&P companies can begin to see immediate benefits when it comes to cost savings and increased efficiencies.

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New Approaches to an Old Industry – Smart Oil and Gas Field of the Future http://www.oilgasmonitor.com/new-approaches-to-an-old-industry-smart-oil-and-gas-field-of-the-future/ Fri, 14 Nov 2014 06:51:54 +0000 http://www.oilgasmonitor.com/?p=8117 Stan DeVries | Schneider Electric While oil and gas prices fluctuate with the latest economic report, the challenges facing companies extracting those fuels are less volatile. Instead, those challenges could best be characterized as complex and well-known. Without smart, integrated solutions, companies could waste tens and hundreds of millions of dollars a year. However, there […]

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November 14, 2014
Stan DeVries | Schneider Electric
While oil and gas prices fluctuate with the latest economic report, the challenges facing companies extracting those fuels are less volatile. Instead, those challenges could best be characterized as complex and well-known.

Without smart, integrated solutions, companies could waste tens and hundreds of millions of dollars a year. However, there are intelligent strategies that can be implemented within a Smart Oil and Gas Field to recover hydrocarbons through more cost-effective and enhanced approaches.

Industry veterans know the most accessible oil and gas has already been recovered.

And with that, I pose these questions:

  • What can oil and gas companies do to maximize profitability in networks of small wells?
  • How can engineers and operators benefit from data monitoring without drowning in excess statistics from hundreds of wells?
  • How can the field knowledge of experienced workers be transferred into systems that help key personnel make the best decisions?

To place those questions in context, we need to acknowledge the realities of today’s oil and gas field operations. It is commonplace to see the intentional operation of wells that have flow assurance challenges and reservoirs with relatively short lives. This is especially true for shale oil, gas deposits and turbidites.

This article focuses on the best practices to address those challenges by adopting methods from other industries. The two key strategies that hold transformative power for the Smart Oil and Gas Field are called the Field as a Factory (Faaf) and production surveillance approaches.

Both approaches require a reevaluation of the interaction between systems and knowledgeable workers. The overarching goal is: Delivering only the right information, within the right context, at the right time, to the right people to achieve the most effective results with a Smart Oil and Gas Field.

What’s a 21st century Field as a Factory?

The FaaF approach borrows lean manufacturing principles from the automotive, aerospace and consumer goods industries. The best practices are designed with the recognition that the addition of wells is frequent and there are corresponding changes to the gathering systems, treatment plants and utilities.

For example, in the Middle East, there is a successful execution of the FaaF approach where more than 70 Smart Oil and Gas Fields are integrated into one system with a national remote operations center. There are a variety of local control and monitoring systems. Every time wells and infrastructure are added or modified, the system displays, alarms and reports on more than 1 million field data points while more than 10,000 displays are altered by using standards with a high degree of configuration automation.

The FaaF approach has been in the works for the past two years, developing out of a financial and human resource necessity. The growth in oil and gas extraction from shale formations is a major driver of this practice. In past decades, companies could recover oil and gas from a few large diameter wells that would last for many years.

In today’s business climate, oil and gas are being extracted from small pockets underground. This reality has forced companies to drill literally thousands of small wells in which each might only last for up to six years. This FaaF approach is currently being adopted in the United States, Canada and Australia due to shale formations found in these countries.

Prescriptive data will propel timely decisions

A major advantage of the FaaF framework, coupled with production surveillance, is the emergence of prescriptive data – information that is systematically screened, bringing only valuable and actionable information to the attention of operators.
The system alerts workers when specific wells within the Smart Oil and Gas Field—out of a total of hundreds or thousands—are registering major changes in terms of the flow of oil, gas and water.

This configuration automation is critical as it allows the system to recognize patterns in pressure measurements and ratios of oil, gas and water. The automated system can quickly perform the calculations engineers and other technical staff previously had to complete manually over lengthy periods of time.

One large energy company in the USA estimated that its technical staff was spending up to 70 percent of its time finding and processing information. This heavy portion of data gathering and analysis minimized the staff’s ability to take steps that would continually improve business performance.

The transformative data-based approach has a multiplier effect when it comes to business benefits.

Building a reservoir model is an iterative process. Of course, this begins with one set of information that produces the first version of the reservoir model; from which the field development plan is built. The FaaF principle allows operators to quickly obtain actual and trusted information that can be fed to reservoir engineers to update not only the reservoir model, but also re-define the field development plan, if necessary. The outcome is a model of the Smart Oil and Gas Field that is brought up to speed more rapidly and reliably.

Antidotes to gas pressure loop changes

When best practices are employed in production surveillance it’s much more feasible for operators to address gas pressure loop challenges in a timely and effective manner. After all, production surveillance also was borrowed from a lean manufacturing principle, specifically modelling and simulation from the supply chain.

Today, companies experience multiple challenges in maintaining optimal flow from wellheads, associated gathering systems and processing facilities. Production surveillance solves these issues by enabling flow assurance from different completions that use rigorous on-line simulation from well risers to custody transfer points, coupled with manufacturing intelligence and workflow. These highly automated and trustworthy production management systems have the ability to keep pace with continuous drilling.
Yet, one of the main dilemmas in managing a reservoir is discovering how to increase the oil recovery factor. Even by applying enhanced oil recovery (EOR) techniques, mature fields retain too much oil at the end of the life-cycle of a reservoir. This is mainly due to various reservoir properties and drop in reservoir pressure due to depletion of fluids.

One popular method to recover oil in such reservoirs is by using the gas lift method. An operating company can use part of the produced gas to re-inject it in wells, which can benefit from an artificial lift. Gas is compressed and pumped at high pressure at various well depths to lighten the liquid column and allow the fluids to flow to surface. The gas produced from this process is then recycled to continuously support this artificial lift method. However, even such oil recovery method may fail due to gas availability issues or compression station failures.

The tremendous value of production surveillance is that statistics are gathered and systematically analyzed so that operators of a Smart Oil and Gas Field can be alerted much earlier in the process when a flow problem is about to occur. This presents operators with better options to address the situation before the flow drops to a very low level. An early warning system allows operators to make better decisions about when to use a gas lift. It also helps operators to precisely time the closure of a valve, so a well can be shut down to allow pressure to build up again naturally. Operators who close valves at the right time will extend the life spans of wells and those actions will have a huge impact on company bottom lines. Better treatment of a reservoir only results in increased production; thus, increasing the final recovery factor of a field.

Data monitoring and knowledge transfer

When one takes a holistic view of the industry, many oil and gas fields are deemed economically unfeasible to produce from. Oil and gas wells around the world face far more operational difficulties today as they need to be drilled in extremely remote locations compared to those in service 10 to 20 years ago. This new industry environment means that operators need access to more advanced data monitoring systems in order to operate Smart Oil & Gas Fields efficiently. Once economically unfeasible reservoirs need to be reevaluated in the light of new technological enhancements available to the operators today.

On top of production challenges, there is an apparent skills shortage in the oil and gas industry. The rapid expansion of oil and gas in the last decade, coupled with the fact that universities are finding it difficult to produce enough graduates to meet the industry demand, makes knowledge management a key challenge in the industry. This promotes the case of utilizing advanced data capture and analytics techniques to promote knowledge management.

This will allow companies to maximize impact of employees who are experts in their fields. It is important to embed much of their knowledge into automated data systems that will remain prominent and continue to innovate the Smart Oil and Gas Field long after they retire. Even the most knowledgeable leader can only spend so much time helping other co-workers, whereas solutions can educate an entire industry.

A transformation of work

Currently, a transformation of work is unfolding. Information is being incorporated into automated data systems. These systems can and will increase the effectiveness of workers and the Smart Oil and Gas Field as a whole by providing the right information at the right time.

The return on investment of both FaaF and production surveillance is clear. These strategies can yield millions of dollars in increased revenue annually. Simultaneously, they can save a company millions of dollars in expenses because they enable decisive action on the front end of developing problems.
With intelligent solutions in place, companies can lead the industry to better understand how to operate Smart Oil & Gas Fields most effectively, collecting key information and industry best practices to share along the way.

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Oil Demand and Well Decline Rates Ensure Strong Outlook for Oil Industry http://www.oilgasmonitor.com/oil-demand-and-well-decline-rates-ensure-strong-outlook-for-oil-industry/ Wed, 05 Nov 2014 06:53:03 +0000 http://www.oilgasmonitor.com/?p=8075 Emmanuel Gallezot | General Electric Power Conversion Primary energy consumption continues to accelerate globally despite several years of slow economic growth. With increased consumption, production of oil continues to grow surpassing record level of 90 million barrels per day worldwide. Not only does the oil industry need to produce more to meet ever increasing demand, […]

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November 5, 2014
Emmanuel Gallezot | General Electric Power Conversion
Primary energy consumption continues to accelerate globally despite several years of slow economic growth. With increased consumption, production of oil continues to grow surpassing record level of 90 million barrels per day worldwide. Not only does the oil industry need to produce more to meet ever increasing demand, it also needs to overcome existing well production declines. All active wells ultimately decline in production as resources are tapped, though there is an opportunity for technology to slow or in some cases even temporarily reverse those decline rates. In addition, as existing wells decline, more and more new wells need to be drilled to keep up with demand. Offsetting of oil decline rates for both existing and new wells, therefore, is high on the industry’s agenda for good reason. It is a critical factor to understand future trends in the oil industry.

What are oil decline rates?

The measure of how rapidly the rate of production from an oil field or group of fields declines is called the decline rate. Production decline rates are dependent on several factors, including geology of the well, drilling and completion processes, and enhanced oil recovery technologies in place to manage or optimize production.

All wells and fields are different and there is no precise way to measure cumulative industry decline rates. While these numbers vary based on several factors, general trends can be gleaned from different sub-segments of oil wells, and those trends are indicative of major industry trends. For example, in 2008 IHS estimated global oil field decline rates to be around 4.5%. In the same year, IEA did a study estimated the worldwide decline rates to be around 6.7%. Both studies took place prior to the phenomenal North American increases in tight oil production beginning in 2010.

In general, here is what the industry knows:

(source: IHS, Deloitte & Touche and USGS databases; other industry sources; IEA estimates and analysis)

  • The supply of the oil from an existing fields decline on an average of 5-7% per year
  • The largest onshore oil fields decline at a slower rate
  • Deepwater offshore fields decline 2+ times faster than onshore fields
  • The latest onshore tight oil fields in North America show annual decline rates greater than 30, 40, & 50% in the first years before the rate asymptotes to a more traditional decline rate

So: onshore tight oil has the highest decline rate, whilst deep water offshore wells rank the second. Large onshore conventional wells have the lowest relative decline rate among the three.

A rising decline rate of the global oil production

According to Infield Systems’ Offshore Energy Database, total offshore oil production accounted for approximately 6% of global production back in 1965. But this proportion has been steadily increasing over years. The figure rose 33% between 2000 and 2010, and prospects for the future remain equally positive, with offshore oil production expected to account for ~35% of global oil production by 2015.

It is the same story for the U.S. tight oil production, which has increased dramatically in just the past few years, from less than 1 million barrels per day (MMbbl/d) in 2010 to more than 3 MMbbl/d in the second half of 2013.

It is clear that as the industry goes forward, the mix of high decline fields will grow much faster than production from lower decline onshore conventional fields. This is especially the case as the focus continues to shift to new offshore developments and onshore tight oil to primarily sustain the level of production required to meet increasing global demand.

Given the much higher decline rates of offshore production and of onshore tight oil compared to onshore conventional production, we can clearly see that more technology and more wells will be needed in the coming years to offset the decline rate.

A new look at the future of the global oil industry

Oil demand growth is currently moderating, prompting the IEA to note a relatively weaker outlook for crude oil demand in 2014 and 2015 to 900,000 b/d and 1.2m b/d. But this figure does not slow industry growth. Actually the opposite is true: given the increasing decline rates, the oil industry will expect considerable capex investment and increased growth.

Since decline rates are increasing in the new oil industry mix, more wells need to be drilled to merely deliver against existing demand, even without growth. Inevitably, more O&G equipment and services will be needed to support the increasing production activities. In addition more and more knowledge and technology will be implemented on existing wells in the coming years to soften decline rates and extend production.

The oil industry will increasingly invest capital to implement technologies focused on more efficient oil production to offset the decline rates. The invested capital is likely to increase every year, and the industry will demand not only better technologies, but also more efficient and cost effective technologies.

Some potential technologies that will become the game changers

As the conventional “easy” reserves are exhausted, energy producers will need to push the limits of technology to gain access to resources in new and extreme locations, including distant offshore and deep-sea resources and shale deposits; reserves that might have been seen as economically unviable a few years ago.

Sub-sea extraction involves moving to ever deeper waters and more challenging environments. The deeper we go in future –3,000m below sea level and beyond- the higher the costs and risks involved in processing resources topside. Even though sub-sea production is still in its infancy, the potential advantages are many. The equipment is generally maintenance-free, greatly increasing up time as well as decreasing offshore travels.  Subsea production is significantly more cost-efficient and energy efficiency not to mention improved safety. However, the biggest advantage is that — thanks to putting the platform on the seabed — there is greatly improved compression, increasing the long-term production lifetime of the platform with recovery rates also increasing considerably. More compression means greater amounts of recoverable oil.

The next big step for subsea operations will be to separate oil, gas, water and sands close to the well. Subsea separation saves a lot of energy, as the entire stream does not have to be pumped from the seafloor to the platform. The result is that less water and sand have to be discharged back into the sea. In the oilfields of the future, there will be less need for surface platforms, and ‘subsea factories’ may become a more common solution. In many cases it will be the only way to recover resources from smaller oil and gas fields and the only way to access remotely located oil fields, for example, under ice.

Remote monitoring enables onshore resources to remotely troubleshoot and support issues across an entire offshore asset base, saving considerable manpower and time over having dedicated specialists on each vessel. A key enabler to deliver this is an onboard system capable of capturing and diagnosing the issue, and then rapid connection with the shore based support team, either through remote monitoring technology or data packages automatically emailed to the beach. This would allow onshore specialists a potential real-time view of the ongoing performance of key onboard assets, helping to ensure that problems are resolved either before they occur, increasing availability and productivity, or rapidly after they occur, reducing downtime. If a fault is found, onshore experts can remotely diagnose and advise on necessary measures, or travel out to a site to support and correct it if necessary. This ‘lean manning’ approach could have a dramatic impact on the future oil industry.

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What’s Next for America’s Biggest Oil & Gas Producing States: Wyoming http://www.oilgasmonitor.com/whats-next-americas-biggest-oil-gas-producing-states-wyoming/ Mon, 29 Sep 2014 13:21:01 +0000 http://www.oilgasmonitor.com/?p=7832 Roger Soape

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September 29, 2014
Roger Soape & Marc Randal Strahn | American Association of Professional Landmen
The oil and gas boom may be relatively new to Wyoming, but energy most definitely is not. Just as Texas dominates America’s oil production, Wyoming is No. 2 in the country for total energy production, accounting for roughly 40 percent of total U.S. coal production in 2012 and further ranking as America’s leading producer of uranium for nuclear power. In fact, the Wyoming State Geological Survey (WSGS) estimates that if Wyoming were to cease production of coal, natural gas and uranium, much of the country would go dark within a couple of months.

Now, Wyoming is also becoming a national leader in oil and gas production as well, currently ranking as the eighth-largest crude oil and the fifth-largest natural gas producer in the U.S. Last year, crude oil production jumped nine percent to roughly 69 million barrels and the number of proved oil reserves was increased to 706 million barrels.

Like in other oil boom states, Wyoming’s economy has flourished as a result, not just in energy but in manufacturing, trucking and other related industries. During the same time, Wyoming’s gross domestic product (GDP) rose 7.6 percent, with much of that growth coming from the oil and gas industry. The June 2014 Wyoming Insight Report showed that the oil and gas industry now provides 17,100 jobs, 400 more jobs than in May 2013.

The same report estimates that this economic growth will not slow down anytime soon as unconventional drilling and new technologies reawakens existing plays and pipeline export capability continues to expand to U.S. markets to the east and west of Wyoming. Wyoming is just getting started in the horizontal development of its resources and has a very strong future for additional development in this area. In May, Wyoming’s oil production passed 200,000 barrels a day. Some industry experts are saying that oil and gas development in Wyoming will continue at this pace for the next 20-25 years.

A ‘Wonderland’ of Potential

Earlier this year, a WSGS report called Wyoming a “wonderland” of energy potential for America. This “wonderland” remains concentrated in the southeast and central portions of the state at this time as companies continue to chase oil related projects versus the gas driven projects primarily found in the western half of the state because of the current price for gas. Wyoming Oil and Gas Conservation Commission (WOGCC) data shows that Niobrara oil production increased from 365,000 barrels in 2010 to 3.5 million barrels last year, with much of this production in Converse, Campbell and Laramie counties – the heart of the Niobrara shale play in Wyoming. This trend has continued in 2014. Of the 36 active rigs in the state as of September 5, all but six are located in these three counties.

However, the Niobrara shale is only one player in Wyoming’s burgeoning E&P potential. Nestled within the minerals-rich Powder River Basin that covers much of the state, legacy formations such as the Lance and Tensleep regularly produce in excess of five million barrels annually. Other primary objectives in the Powder River Basin are the Dakota, Frontier, Parkman, Turner, Sussex, Shannon and Mowry Formations. Earlier this year, Chesapeake Energy praised initial output from a new horizontal well in the Sussex formation, claiming it produced nearly 232,000 barrels of oil, or 1,500 barrels per day, in five months. The Frontier formation has also shown impressive figures, increasing from 1.4 million barrels in 2010 to nearly 2.2 million barrels in 2013.

Amidst these figures, production in the Powder River Basin is forecasted to sharply increase in the near future. Much of the northern half of the Powder River Basin is under a development restriction from the Buffalo Field Office of the Bureau of Land Management while they update their Resource Management Plan for the majority of the Powder River Basin. Activity is expected to pick up greatly once the Resource Management Plan is completed by the federal government.

In addition, the Codell formation, located farther south in Laramie County, has already exceeded 2013 levels by more than 200,000 barrels and exceeded Niobrara production levels in the first half of 2013. In August, Anadarko Petroleum and EOG Resources announced that test wells in the Codell formation were “extraordinarily economic” and comparable to what Anadarko has seen other highly productive plays areas elsewhere.

Yet as new technologies change the drilling game, operators are still conducting a fair amount of exploration and speculation to determine Wyoming’s most productive fields and how best to drill in the region. In some instances, formations like the Niobrara, Sussex and Frontier are stacked on top of each other – a very unique arrangement – making it easier for oil companies to drill. Companies can drill multiple wells and target multiple formations through a single pad, lowering production costs and significantly limiting surface disturbances.

However, drilling for the tight-sands oil in Wyoming’s shale is still a massive, costly endeavor, typically spanning two miles horizontally underground and costing between $5 million and $10 million. Higher oil prices will continue to be a primary driver in making these developments possible.

Growth and Regulation

From a regulatory perspective, the state of Wyoming, like other states, is still trying to define the parameters of regulating and overseeing oil and gas production. As Wyoming’s strong oil industry becomes established, the largely understaffed WOGCC has been working overtime to set regulations ensuring safe, steady industry growth that have long been in place in other oil-rich states.

In September, the WOGCC unveiled a proposal to increase the minimum distance between drilling rigs and occupied dwellings of 500 feet for vertical wells and 750 feet for horizontal rigs. The current setback requirement of 350 feet lagged behind those of other oil and gas producing states such as North Dakota, Colorado and Texas.

Wyoming’s Infrastructure Authority – formed in 2004 to help spur development of oil and gas pipelines and power lines – has also been striving to move long-awaited, much needed power line projects forward. However, pipeline development, as in all of the oil boom states, has been struggling to keep pace with the rapid growth of the industry.

The rail system has also proved to be in need of increased oversight. Oil shipments by rail have expanded greatly – increasing 61 percent in 2013. Amid widespread concern over crude oil shipments by rail, the task of addressing safety issues in Wyoming has been mostly left up to local governments.

And from a legal perspective, the Wyoming Supreme Court recently passed a new ruling exempting landman responsibilities as an unlicensed practice of law, further clarifying the role of landmen for landowners. Our organization, the American Association of Professional Landmen, was one of the leading drivers of this change.

Mark Watson, the newly appointed director of the WOGCC, as well as Gov. Matt Mead have said that possible regulations for groundwater testing, gas flaring regulation and bonding requirements for oil and gas wells are also in the works. During this time of rapid oil and gas development and economic growth for Wyoming, it is critical that the industry work alongside the WOGCC and other state regulators to establish policies that make sense — and allow communities to experience the full economic benefit of oil and gas development.

A Baseline of Shared Knowledge

While regulating bodies are critical to establishing safe and sustainable practices, it is also up to those of working in the industry to educate local communities on safe drilling technologies and techniques. While the oil and gas industry has been present in Wyoming for decades, horizontal drilling has not. The industry should proactively educate residents on horizontal drilling technologies and responsible drilling practices so they know what to expect.

Contrary to some reports, responsible management of water and the preservation of Wyoming’s forests and wildlife are priorities for developers in the area. The U.S. Forest Service’s reconsideration to lease more than 41,000 acres of the Wyoming Range has prompted opposition from statewide fishing and conservation groups. Yet, horizontal drilling techniques now allow companies to access the gas reservoirs well below the surface of those acres without disturbing the natural beauty above. Companies interested in leasing the land have volunteered to sign a no-surface-disturbance stipulation with the Bureau of Land Management.

In addition, a recent study conducted by Golder Associates, a global engineering and environmental consultancy, shows oil and natural gas activities in the six major western producing states of Colorado, Montana, New Mexico, North Dakota, Utah and Wyoming use markedly less water than agricultural, municipal, recreational, and other industrial activities – about 1 percent of the area’s total water use. At the same time, industry researchers around the country are working to develop new ways to use less water in horizontal drilling and sanitize the water after it is used.

Oil and gas development is a partnership between the industry and the community that builds cities and revitalizes economies, but without a baseline of shared knowledge between the two, the full benefits and impact of oil and gas development cannot be realized.

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“Great Crew Change” Affecting Offshore E&P and at Greater Numbers than Onshore http://www.oilgasmonitor.com/great-crew-change-affecting-offshore-e-greater-numbers-onshore/ Fri, 26 Sep 2014 12:00:31 +0000 http://www.oilgasmonitor.com/?p=7820 Christopher Melillo

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September 26, 2014
Christopher Melillo | Kaye/Bassman International
As Cuba is no longer focusing on offshore development and with many operators, especially US firms, foregoing any possibilities of keeping the offshore talent close to home in the Caribbean with development opportunities due to the embargo, this lack of needs does not alleviate them from a brutal war for talent as there is an overall increase continuing to grow in offshore development. This also spreads the talent needs geographically, without very much concentration in one area as there are very few regions that are decreasing output or exploration.

But, the biggest strain on talent has come from the tremendous success of North American Onshore development that has occurred within the last decade. Because there are more and more independent producers coming on-line or coming of age, they are depleting an already shallow pool of talent which exists in Oil & Gas. If you’ve read any of my previous articles, you have seen the qualified professional to existing position ratio of 3:5. The scale for offshore is even greater as it is not replacing the professionals exiting Offshore at nearly the same rate as the Onshore producers have. With the “ideal” experienced candidate being an individual with 8-12 years’ experience, that undergraduate talent pool which comprises this level of experience has been almost entirely absorbed by the Onshore market since 2002. Creating an even larger gap in this scenario is the fact that attrition is retiring senior level professionals at a similar rate as Onshore, the growth/experience of the junior staff does not increase at an identical rate to them as capable as an Onshore professional to assume higher levels of responsibility. This is not saying one is better or more intelligent than the other. It is simply statement that leadership will state takes longer to develop due to differing complexities of the differing plays.

Specifically, the Geologist, Geoscience and Geo-technician discipline(s) have been the hardest hit and in the most need as Offshore exploration continues to grow at a faster rate than Onshore. As these are such specialized needs in the Offshore market requiring a senior level of experience, they are going to suffer even more in the next 5-7 years as the gap created since 2002 will not have been closed at more than 25% of the departure rate, by that point in time. While many of the larger firms are attempting to cross-over some of their incumbent talent, this has been recognized as a positive sign towards a remedy for this talent shortage. However, with the recent undergraduate talent pools being trained and/or experienced in Onshore work, many firms willing to hire them find compensation to be an issue. Those individuals are being compensated for their current value in a role that can be immediately validated, but the hiring firms must now look at individuals who they may feel are not worthy of the transfer compensation required to get that candidate as he or she does not have the Offshore experience. While many of the larger operators are able to adjust, there are issues that still arise with regard to retention/internal equity. This becomes a slippery slope for many benefits & compensation teams and many firms seek remedies from the talent acquisition leadership. However, you can’t hire what does not exist. In many cases, candidates open to switching from Onshore to Offshore should consider small dips in compensation so they may increase their capabilities and create what many perceive as a better career path within the E&P industry. Unless these organizations either directly or through third-party consulting help educate the market on that possibility, most of the current Onshore talent will remain where they are. The Majors have been successful in developing training programs to get their professionals up to speed quicker than they ever have in the past. Those firms also realize, they are still unable to replace senior level experience with the greatest training in the world. The Offshore Talent War is the one you hear about less in Oil & Gas than Onshore, but it is the one that is really worse off. But, the great news of all of this is that means the job numbers continue to be strong and are climbing as these are not just replacing the retiring market (aka “Great Crew Change) these are also new opportunities coming about.

Where are the jobs?


With larger discoveries recently occurring off of Western Australia and Equatorial Guinea, two fairly active areas already, the remainder of the market without sizeable discoveries is still struggling with keeping their staff whole. The greatest effect of this growth is also hitting the service market as well as an ever increasing number of needs for professionals performing corrosion inspection to sub-sea welding. Once again, we see that Majors are doing an excellent job of developing these types of roles in-house as opposed to being entirely dependent on third parties.

Another part of the service side that is continuing to grow will be in Marine/Shipping as larger staff will find opportunities in HSE roles. With the recent passing of liability increases for shipping, many organizations will step forward to improve or maintain the highest standards as the costs for mishaps will far outweigh payroll/staffing increases.

While Houston has the majority of Petroleum/Reservoir Engineering and Geoscience needs, Petroleum Engineers in the UK, Saudi Arabia, Turkmenistan, Denmark and Nigeria are the next areas with the highest demand. Workover & Completion roles are heaviest in Turkmenistan, Ghana and Baku. Deepwater Completion needs are the highest Ghana & Nigeria. The offshore Operator job needs are most significant in GOM and the North Sea has shown an overly proportionate need for Drilling Engineers.

To say there is a surge of opportunities for Offshore talent would be a gross understatement and the operators in need of this talent have done a very good job of staying competitive to attract these professionals. Unfortunately growth has well surpassed capacity and the market needs to continue finding ways to transfer Onshore skill sets to perform Offshore as well as continue to educate the potential market of talent at the campus level.

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Independents Reshape the Playing Field – Why it’s a Good Thing. http://www.oilgasmonitor.com/independents-reshape-playing-field-good-thing/ Wed, 06 Aug 2014 10:06:56 +0000 http://www.oilgasmonitor.com/?p=7588 George Koutsonicolis | SOLIC Capital Advisors We’ll soon see big changes in Oil and Gas. Risky exploration, spearheaded by emerging independents, is the inevitable future of this industry that has spent years exploring only existing reserves.   One of the most talked about trends of the last decade has been the rise of the independents. […]

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August 6, 2014
George Koutsonicolis | SOLIC Capital Advisors
We’ll soon see big changes in Oil and Gas. Risky exploration, spearheaded by emerging independents, is the inevitable future of this industry that has spent years exploring only existing reserves.
One of the most talked about trends of the last decade has been the rise of the independents. According to a recent audit by EY, U.S. oil and gas reserves increased 9 percent last year and almost all of it was due to independent exploration and production (E&P) companies — not the large integrated oil companies.

Wedged between investor demand and the high cost of exploration, supermajors are incentivized to focus on short-term financial results. Their long-term strategy relies on established oil and gas reserves and producing wells operating long enough for supermajors to squeeze – or buy out – independents.

This is a thinly veiled long-term strategy. While many independents will fail (or run out of financing trying), some will stick around. Those that remain will have found new oil and gas reserves at a time when the supermajors have no Plan B. I think we all know who holds the power in this scenario.

Without a doubt, executives from Big Oil are realizing that they’ve fallen behind in the search for new deposits and the resultant consequences. Extensive exploration is fraught with substantial risk, and the hand of public ownership is a heavy one – especially when it means writing blank checks for an unknown amount of time.

It’s the appetite for and ability to manage these inherent risks that separates independent E&P companies from supermajors. The independents are not just technically savvy, as evidenced by their embracing of new exploration technologies, they have established rigorous decision making processes necessary to chase high risk projects. Immense risk is built into their business plan in a way supermajors cannot mimic.

Independents are emerging with a level of entrepreneurial discipline that will only help them as they grow into public ownership.

What This Means

While it may seem that supermajors should pursue riskier exploration in an effort to get ahead, I don’t see this actually happening for several years. Supermajors will need shareholder support to back an appetite for risk, and without a core group of large shareholders with the same appetite for risk, that’s a difficult conversation. There’s too much uncertainty for the average investor.

What is clear: any oil and gas company that wants to be successful will need to be riskier with exploration than companies have been in the past. Competition, increasing demand, and cutting-edge technology are changing the landscape.

When the day comes of supermajors feeling their exploratory lag, they’ll look to buy out independents, some of whom will have maxed out their spending to get ahead. Certain independents will sell at a high premium, trading their independence and control for a solid balance sheet. Supermajors will get the results of exploration while having minimized their exploration risk.

And yes, this will come at a high price for supermajors – likely higher than the cost of exploration itself. It’s easier to answer to shareholders with proven reserves and oil already in the rig.

In other words: there is a future of high-value M&A.

This will result in a dual-path approach to exploration. One side of the business will be as it always has been – buying up existing reserves. The second path will be pursuit of high-risk exploration, led by lean independents who will ultimately be acquired by or partner with supermajors. The industry will at long-last have a short and long-term strategy.

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Oil & Gas Services: The Place to Be? http://www.oilgasmonitor.com/oil-gas-services-place/ Wed, 09 Jul 2014 12:47:32 +0000 http://www.oilgasmonitor.com/?p=7450 Lorraine L. Walker

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July 9, 2014
Lorraine L. Walker | BDO
In a recently held roundtable discussion with executives in the oil and gas industry, the issue of increased demand in this sector was raised. This sentiment was echoed by attendees and presenters at the International Energy Capital Forum that was held during the Global Petroleum Show in Calgary, Alberta.

Canada’s oil and gas resources are effectively landlocked; to supply new markets in the US and abroad, producers need a method of transportation other than rail. This means that service companies will potentially be working at capacity in the next decade to build pipelines and processing plants. Producers will be forced to drill the product fast enough in order to utilize this infrastructure to its optimal capacity. The challenge for Canadian service companies will be to keep pricing competitive in order to continue to meet oil and gas production demands north and south of the border.

In order to meet demand, oil and gas service companies will have to hire approximately 58,600 people by 2022 (Petroleum Human Resources Council of Canada, The decade ahead: Labour Market Outlook to 2022 for Canada’s Oil & Gas Industry, May 2013, retrieved from: www.petrohrsc.ca) primarily in areas such as drilling and completions, geophysical, and other petroleum services. While this projection will meet Canadian production demands, it does not anticipate service company requirements for those who want to explore opportunities in the US or other international markets. In recent years, Canada has been having a tough time supplying its own need for skilled labor. To further compound this, the recent increase in US production of gas in the Marcellus and other shale plays has resulted in a southern migration of our talent. This increased need for skilled labor on the service side was a hot topic at both the World Oil Council event in May and the Global Petroleum Show in June. Executives we met at both conferences felt that their biggest barrier to growth was access to capital and skilled labor in the service sector. They need suppliers who can drill, their product moved to market, and the infrastructure built to do so.

It seems that the place to be is the oil & gas service sector in Canada. As US production ramps up with unconventional plays and the demand for skilled labour increases, there will be an increased interest in companies that can develop new technologies to not only improve production and profitability, but the environmental impact of the industry. Providers who can keep their pricing competitive while responding quickly to these new demands will be well positioned for growth in the future.

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What’s Next for America’s Biggest Oil & Gas Producing States: California http://www.oilgasmonitor.com/whats-next-americas-biggest-oil-gas-producing-states-california/ Mon, 09 Jun 2014 11:59:16 +0000 http://www.oilgasmonitor.com/?p=7285 Roger Soape | American Association of Professional Landmen While the Gold Rush of the 1840s set the historical stage for California, the state sits atop a similar opportunity in “black gold,” which if fully realized, could positively change the landscape of the state in a dramatic way once again. California’s history with oil and gas […]

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June 9, 2014
Roger Soape | American Association of Professional Landmen
While the Gold Rush of the 1840s set the historical stage for California, the state sits atop a similar opportunity in “black gold,” which if fully realized, could positively change the landscape of the state in a dramatic way once again.

California’s history with oil and gas production has been just as storied as the Gold Rush. Some might say it’s had an even more significant impact. Oil production has been a key driver of the state’s economy since 1866 when the first well was drilled Ojai, located northwest of Los Angeles, using a steam-powered rig.

California quickly became an oil production powerhouse. Although production peaked in the 1960s, the state saw annual production in the neighborhood of 380,000 barrels a year into the mid-1980s, according to the U.S. Energy Information Administration. But that production has consistently declined in the three decades since.

Today, California sits third behind Texas and North Dakota in terms of crude oil production (generating 15,503 barrels a day) and ranks 13th in natural gas production (at 246,822 million cubic feet of production in 2012). And there’s enormous potential for growth.

This potential for growth is not just in terms of energy production and economic revenue, but in jobs. In 2012, the petroleum industry was responsible for roughly 468,000 jobs in California, according to a study by the Los Angeles County Economic Development Corporation. The vast majority of those are located in the six counties of Southern California, particularly Los Angeles.

However, as production within the Monterey Shale ramps up, those opportunities are expanding in ways that benefit the entire state.

Exploring the Monterey Shale

While commercial production in the Monterey formation dates to 1977, the area has received increased attention in recent years. It became the key focal point in 2011 after the Energy Information Administration estimated that more than 15 billion barrels of recoverable oil is trapped below the formation. The shale area spans 1,750 square miles, roughly from Bakersfield to Fresno.

Yet, the path to unearthing that oil is anything but easy, at least at the present time. Shale formations across the U.S. can typically be accessed through a single well with multiple horizontal shafts, drawing oil from a wide geographic area. Unlike the older Bakken and Eagle Ford Shale plays, the Monterey shale is estimated at six to 16 million years old. Seismic shifts in the earth have reshaped the substrate by folding, stacking and fracturing it, and as a result recoverable oil lies far below the levels found in other shale plays.

To reach the vast pools of oil below the Monterey Shale by conventional methods would require drilling far deeper. The shale ranges in depth from 8,000 to 14,500 feet. Thus, accessing the oil under the Monterey formation is requiring hefty investment for oil and gas companies.

In many parts of the country hydraulic fracturing is primarily used to extract natural gas. In California, however, hydraulic fracturing has also been used since the 1950s to extract liquid oil. To access the reserves buried under the Monterey Shale, oil and gas companies are experimenting with hydraulic fracturing and other well stimulation techniques. These include technologies, such as matrix acidization, acid fracking, steam injection, carbon dioxide flooding and dry fracking.

Yet, alongside this vast opportunity in the Monterey Shale has also come much debate about regulations to monitor oil and gas companies looking to implement hydraulic fracturing and other well stimulation technologies. Senate Bill 4, in particular, has been at the forefront of the conversation. SB 4 has introduced a host of compliance issues, such as: requiring oil and gas companies to apply for fracking permits, publicly disclosing chemicals used in fracking, notifying neighbors before drilling and monitoring ground water and air quality, among other requirements.

Although the SB 4 was passed in September 2013, there is still much confusion about what the bill entails exactly, particularly because there have been numerous amendments to it. Interim regulations have been put into place, with the bulk of SB 4 going into effect starting January 1, 2015.

The Untapped Opportunity

The Monterey Shale presents an untapped opportunity for the industry and the state of California. Based on a 2013 study by the University of Southern California (USC), the potential economic impact of the Monterey Shale is huge. The study, conducted by the USC Global Energy Network, used sophisticated economic modeling to conclude that fully exploring the Monterey Formation could result in:

  • Job growth of anywhere from 512,000 to 2.8 million new jobs in California;
  • Gross domestic product increasing by 2.6 percent to 14.3 percent on a per-person basis;
  • Aggregate personal income gains of 2.1 percent to 10 percent; and
  • Tax revenue collected by California state and local governments increasing from $4.5 billion to $24.6 billion.

Clearly, the Monterey Shale has taken center stage when it comes to California’s future. There’s much left to be discussed and discovered related to public policy and the technological developments that will enable oil and gas companies to explore the shale’s full potential.

From the Gold Rush of the early nineteenth century to the Silicon Valley developments of the late twentieth century, California has set a high bar when it comes to leveraging innovation and risk to realize greater rewards. With so many opportunities that have yet to be realized in California, the Monterey Shale could, in fact, put the state in the history books once again.

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