Oil price decline driving greater potential for efficiency and technology innovations in oil and gas operations

Upstream technologies and innovations saving millions and improving productivity

Persistent low oil prices are taking their toll on both industry profits and spending projections for future oil and gas projects, presenting an opening for exploration and production (E&P) technology and innovation to continue proving its worth in helping to lower industry capital and operating costs.

Operators are taking meaningful actions to reduce costs in response to the lower oil price environment, including increasing capital discipline, pursuing a range of cost-cutting initiatives, reducing workforces, cancelling rigs, and placing a greater focus on standardization. In assessing the technologies that offer the greatest opportunities for driving down capital and operating costs, we at IHS have identified several "pockets of technological excellence" where we think the greatest potential exists to impact costs in the near term for the oil and gas industry.

Areas of interest include new technology-enabled field development concepts, higher levels of automation along with applications of unmanned systems (e.g., drones), more prolific and advanced sensor networks coupled with data-driven analysis, and technology-enabled efficiency improvements in major project executions.

One approach includes adapting manufacturing-style drilling techniques-which have been applied so successfully in unconventionals to reduce costs-in more conventional asset types as well. Another involves realizing substantial capital expenditure (CAPEX) and operating expenditure (OPEX) reductions through extreme de-manning; or significantly reducing the staff required to operate an oil and gas facility. Some of these capabilities could be achieved through expanded use of remote operational support and control centers.

Questions remain whether the lower oil price environment will indeed spur broader industry acceptance of these technology-enabled innovations-these pockets of technological excellence. And if so, can they have a meaningful impact on overall industry performance?

IHS Energy believes the conditions are right, but it will require commitment and leadership on the part of individual company management. After all, if it was easy, everybody would be doing it.

Focus on areas of greatest potential value

IHS Energy sees that the key to driving the greatest potential return on technological innovations, such as those identified above, is for companies to focus their efforts on the most substantial cost categories (e.g., drilling and completion, other CAPEX, OPEX) within their asset portfolios, and on those projects with the greatest potential return. A number of operators in the U.S. onshore shale plays are focused on their portfolio of drilled but uncompleted wells that offer the greatest potential return, while, from a technology standpoint, some operators are drilling longer lateral lengths. This eliminates the cost of drilling the vertical portion of a new well, and at the same time, improves productivity of an existing well. Yet another technique is "super fracking," which involves the injection of significant volumes of proppant per lateral foot of drilling length to release the oil. While super fracking adds costs, for properly targeted wells the end result is a proportionately higher output and an increase in overall well productivity.

For operators that focus their efforts on the most productive resources in their portfolio, the investment could pay significant returns. According to our research, leveraging the technological innovations identified here have the potential to achieve significant cost reductions-up to 10s of percentage points-in selected assets, but the challenge now is for operators to apply these techniques more widely across their portfolios, in order to drive learning and to leverage economies of scale. One method being employed by some operators in the North American unconventional plays is to adopt a manufacturing-style approach to their well construction processes, which benefits from the hundreds, and in some cases thousands, of wells drilled.

In assessing this potential, the president of a major global E&P company was recently quoted as saying, "Lean manufacturing is one of the key capabilities that is being developed in the Bakken play to benefit our operations there, and unconventional operations elsewhere." Meanwhile, the CEO of a medium-sized US independent said, "Profitability in resource plays is all about optimizing the wellbore manufacturing process." A third executive vice president from a super major said, "… the Lean Process-based Business Model is being applied across our global operations…to help produce oil economically from fields with dispersed hydrocarbons and a high number of wells."

In our assessment of these technologies, IHS Energy has identified the following elements that best define the "manufacturing mindset" in the sector as:

• Standardization and automation
• Data-driven continuous improvement
• Remote drilling support
• Integrated planning and supply chains

In the case of a tight-gas play, standardization would be focused on well and completion designs, while data-driven continuous improvement would target both the rig crew (e.g., its tripping and connection efficiency) and the overall drilling process by defining and achieving optimal drilling parameters by reservoir zone.

IHS found that while drilling performance in unconventionals is becoming more efficient as noted in the graph (see below), the opposite is true in conventional wells. Drilling efficiency in the Eagle Ford play increased nearly 150% from 2010 to 2014 (measured by feet drilled per day), as an increasing number of wells drilled provided the opportunity to apply these manufacturing principles. The opposite was true for conventional wells drilled in Europe, where IHS analysis shows drilling performance (measured by meters drilled per day) declined 37% from 2009 to 2012. In one instance, well costs across eight Norwegian fields doubled from 2006 to 2012.

We believe that elements of these same manufacturing concepts can be applied to more conventional oil and gas settings as well, if repetitive tasks associated with drilling high-cost, one-off wells can support these forms of 'high-iteration learning," and if the technology can be deployed to enable it. The keys to success are real-time data acquired from drilling rigs; a rules-based system to classify drilling activities; and subsequent benchmarking of crews, rigs, wells, and individual tasks.

For example, rather than a traditional view of drilling operations performance, which involves analyzing data derived from static daily activity reports, some operators are leveraging the technology afforded them through real-time automation to set performance targets and quantify the time it takes to perform repetitive drilling tasks (e.g., pipe-to-pipe connections). When this focused assessment of activity and performance is undertaken, operators can begin to quantify truly productive time versus hidden lost time in their drilling operations.

An industry pilot was undertaken to test this concept, which covered eight offshore rigs (both fixed and mobile) drilling a total of 27 wells. Analysis identified non-standard procedures and sub-optimal performance across the company's rig fleet, leading it to embark on training programs and competency building plans to increase capabilities and competencies. For the rigs that participated in the pilot program, drilling efficiencies improved up to 50%, with a 30% average improvement.

Another way in which technology can help to deliver lower costs is through what IHS Energy terms Extreme Minimum Manning. We investigated a shallow-water gas-condensate case study to quantify potential improvement opportunities for an installation 150 kilometers (93 miles) offshore with production of 25 million cubic meters of gas per day, and 50,000 barrels per day of condensate. The operation is considered the most complex Not Normally Manned installation across the industry, and it is remotely operated from shore, with personnel visits limited to a frequency of two to three days every 45 days. The platform is outfitted with separation, drying, and pumping equipment. To reduce platform complexity, power is generated onshore and supplied via subsea cables, and the oil company installed only simple, reliable, and low-maintenance equipment.

The project achieved a 4% improvement in CAPEX costs and was able to reduce OPEX by 70% compared to equivalent nearby platforms, achieved in part by removing 40-50 people from the platform.

Leveraging these same technology-enabled operating models in onshore environments can also dramatically raise performance. By putting in place remote operations centers, operations teams can monitor, control, and optimize systems from central control-room operations. These remote operation systems have been seen to drive 5-15% OPEX reductions and 2-4% production rate increases.

IHS Energy analysis, coupled with actual industry case studies, demonstrates there is real value associated with technology-enabled cost management solutions. In shallow-water gas projects, IHS identifies a reduction in life-cycle cost of between 9% and 32%, resulting in a savings of $3 to $11 per barrel of oil equivalent (BOE). In terms of oil sands projects, similar efficiencies identified a 4-12% reduction in life-cycle costs, resulting in $2 to $6 per BOE savings. For deepwater oil projects, technology innovations yielded a 2-7% reduction in life-cycle costs, or a savings of $1 to $3 per BOE. These are all impressive numbers at a time when the pressure is on to dramatically lower costs in order to allow a range of upstream oil and gas projects to move forward.

30 October 2015 by Judson Jacobs, Senior Director, IHS Energy
Learn more about IHS Upstream Technology and Innovation Service.

Costs and technologies is one of the principle themes at CERAWeek 2016, Energy Transition: Strategies for a New World, February 22-26, 2016 . Learn more and register.

This article was published by S&P Global Commodity Insights and not by S&P Global Ratings, which is a separately managed division of S&P Global.