Optimising the unconventional

There is a silver lining to the extended low-price cycle for oil and gas; it spurs operators to seek greater efficiencies and payback. “The big value is in increasing the net present value (NPV) and estimated ultimate recovery (EUR),” says David Browne of Trican Well Service. “In the last several years, many operators have been too busy to stop and look at ways to enhance their hydraulic fracturing methods; if something worked for them, they didn’t have time to examine alternatives. Now, they have more opportunities to look at other technologies and examine ways of improving their entire process.”

Although improvements in fracking have been important, getting more bang for the buck extends through the entire process, and operators have explored a wide range of opportunities. According to IHS, O&G firms have trimmed an average of US$30/bbl from break-even costs using a combination of reduced service industry rates, high-grading prospects, and improved techniques.

There is still room for improvement. Optimising production starts in the planning stage, where geoscientists closely examine available data to choose the best prospects. Unlike conventional production, where companies search for stratigraphic and structural formations that trap hydrocarbons in porous, permeable rock, geologists already know that a low-permeability shale formation is rich in O&G. The challenge is then finding those portions, known as sweet spots, where the greatest amount can be released at the lowest relative cost.

Once sweet spots are identified, operators require detailed planning of every aspect of drilling, stimulation and production. Several service companies offer integrated operations (IO) software that allows operators to coordinate geophysical, geological and engineering disciplines. Using IO software to analyse seismic, geological and petro-physical data, integrated geoscience and engineering teams can determine optimal well spacing patterns, length of well laterals, stimulation patterns and surface processing facilities.

Drilling and completions

Using the best drilling technology allows the operator to complete a well more quickly, so that the elapsed time from spud to first flow is minimised. During the last two years, service companies have been stacking older equipment; operators now insist on the newest generation of automated drilling rigs (ADRs). The traditional derrick has been superseded by a self-erecting hydraulic telescoping mast. The mast itself has a hydraulic top drive built in, and is equipped with a torque wrench and automatic pipe handler. Conventional manual tongs have been upgraded to hydraulic power tongs.

The rig functions are controlled by various joysticks that raise, lower and stop the travelling block, and operate the pipe-handler rotation. Drilling information can be displayed in real time, and compared to historical performance in order to consistently optimise weight on bit (WOB) and rate of penetration (ROP).

ADRs reduce non-productive time (NPT) dramatically. While conventional rigs may require 20 loads to move from site to site, comparable ADRs can have as little as four, with the self-erecting mast and other components mounted onto trucks, trailers and skids. Some rigs that are designed to drill multiple wells on the same pad use a hydraulic system in the substructure to ‘walk’ the rig at speeds of 15 - 30 ft/hr between wells. These innovations can add 45 - 75 drilling days per year compared to a conventional rig of similar capabilities.

Steerable mud motors, which use a mud-driven turbine in the bottomhole assembly (BHA), are now being replaced by rotary steerable systems (RSS). The direction of the steerable tool is measured while drilling (MWD), using a directional module that measures inclination and azimuth using triaxial magnetometers and gravity sensors. The system contains a transmitter/receiver to send data uphole through the mud system, and receive commands back downhole. Logging while drilling (LWD), enables the operator to keep the tool in the productive reservoir. According to Rystad Energy, the average drilling speed in US shale plays has increased to from 500 ft/d in 2014 to nearly 800 ft/d in 2016.

In the first-generation of hydraulic fracturing that was employed in the Barnett shales of Texas, the equipment was coiled-tubing plug-and-perf, the liquid was primarily water (with some viscosity-reducing additives), and the proppant was finely-sieved silica sand. The basic system had significant drawbacks, however, including the use of high volumes of fresh water, relatively little control over the pattern and direction of the crack networks, and clogging of the reservoir as the proppant and additives chemically decomposed. In addition, early-generation frack technology was hit-and-miss; typically, only 25 - 33% of fracture stages were as productive as designed, meaning that a minority of the reservoir was being effectively drained.

Advances in hydraulic fracturing have reduced stimulation time and increased production flows dramatically. Packers Plus Energy Services’ StackFRAC HD open hole multi-stage ball-drop system is one of the latest completion technologies that effectively stimulates multiple stages in order to increase induced fracture complexity and provide a superior connection to the reservoir. Packers Plus recently completed a frack in Argentina. Normally, a conventional coiled-tubing, plug-and-perf operation would have taken 220 hours. The StackFRAC HD completion was successfully accomplished in seven hours, saving the operator approximately US$280 000.

The volume of frack fluid used in a major stimulation can easily exceed 5 million l. Most of the fluid is fresh water. If an operator wishes to create large dominant fractures in the reservoir, they use a high viscosity frack fluid. Materials such as guar gum and other thickeners are mixed at surface to create a thick fluid capable of suspending large volumes of proppant at lower pump rates.

Proppants are typically made of spherical silica sand grains or tiny ceramic beads approximately 0.5 mm in diameter. They can exceed 500 000 lbs per well. The smaller the size, the longer the proppant stays in suspension, thus assuring it reaches the very limits of the fracture. Larger-sized proppants allow greater conductivity (the ability of gas and oil to flow freely), as does higher sphericity (roundness). The material must be strong enough to resist crushing by the surrounding rock.

Proppant suppliers have been working on new materials and technologies. CARBO Ceramics offers Kryptosphere, a high-density proppant. The engineered material, made of ceramic, was originally designed to meet the extremely high pressures encountered in deep wells in the Gulf of Mexico. Each grain is highly spherical, mono-sized and features a smooth surface. Capable of withstanding pressures up to 20 000 psi, the proppant creates uniform pore throats that maximise available flow space and minimise fines trapping. It is also less corrosive to well equipment, reducing failures in downhole tools.

Fairmount Santrol has devised Propel SSP, a self-suspended proppant that is touted to maximise fracture penetration. A sand grain is pre-coated with a polymer prior to mixing. When the grain comes in contact with water, the polymer swells into a hydrogel layer three times the size of the grain, effectively reducing the specific gravity by half and lowering the grain’s surface friction. This allows the grain to ‘float’ much further into the fracture network. The process eliminates the need for water sweeps, significantly reducing water needs and pumping time. The company notes that some operators in initial field trials are recording hydrocarbon production increases of greater than 50% within six months.

Electrical submersible pumps (ESPs) are a critical component in crude production. Over 130 000 ESPs are in use around the world in high-asset wells, accounting for approximately 60% of the world’s oil production. While manufacturers are continually working to increase run times in all types of plays, unconventional wells present significant problems. Since a shale well can reduce production by over 70% in the first year, having a reliable tool is critical.

An operator in the Permian basin was experiencing ESP run times of 180 days. In order to increase its ESP performance, the operator consulted Halliburton. Halliburton installed its REDlift system, which includes a wide-range ESP and downhole equipment to create controlled drawdown and stabilised pump intake pressure. The system more than doubled run time and increased production by 11%.

Success stories

Although optimising production varies from region to region, most shale plays show significant improvements. According to the US Energy Information Administration (EIA), the new-well oil production in the Bakken has risen 40%, to 690 bpd, in 2016 alone. Other plays have shown similar gains, with the Eagle Ford rising to 1395 bpd and the average new well in the Marcellus now producing 12.7 million ft³/d. In addition, average EURs have risen in all major shale plays, with the Permian Delaware now averaging nearly 1 billion boe.

In Canada, the Montney formation in northeast British Columbia (BC) and northwest Alberta has been the major unconventional play. First Energy Capital Corp, using government and industry data, estimates that the play holds 282 trillion ft³ of gas and 12.8 billion bbl of crude and NGLs. Production has risen dramatically over the last several years, and now stands at 5 billion ft³/d, approximately one-third of Canada’s total production.

Seven Generations Energy owns 0.5 million acres of land in the Montney play, holding over 1 billion boe of proved-plus-probable reserves. With 3300 potential drill sites, the company places a premium on delivering value in each well through the use of the best technological advancements. The company has sped up drill time by 40% using underbalanced drilling technology and new well design. It has also increased stages-per-well to 33, with 162 t of proppant per stage. The result is a 25% reduction in well costs and higher hydrocarbon fluid yields. “What is most important is that evidence for the optimised resource recovery shows that our wells are actually producing above our type curves,” says Glen Nevokshonoff, senior vice-president, operations. “We are seeing higher condensate yields from our slick water fracks and it gives us confidence that we’re doing the right thing.”

Concerns

The rapidly evolving nature of unconventional production has created significant challenges. Critics are worried that hydraulic fracturing uses up valuable water resources and injects harmful chemicals that have the potential to pollute groundwater. Several states have enacted legislation restricting the process, and other jurisdictions, including Quebec and France, have instigated blanket bans.

Industry is responding through a number of initiatives, including recycling flowback, purifying water, and using low-impact frack chemicals. Calgary-based Aqua-Pure has developed a mechanical vapour recompression evaporator mounted on truck-transportable skids. The system converts contaminated frack flowback water into pure water at a rate of 60 gpm (13 m3/hr). Chesapeake Energy, one of North America’s largest natural gas producers, is experimenting with frack additives composed solely of environmentally benign components. Various mixtures of the 100% green fluids are being field tested in wells throughout the US.

The recent appearance of earthquakes in previously dormant regions has also been associated with unconventional production. In November 2016, a 5.0 quake epi-centred almost directly under the massive crude storage facility in Cushing, Oklahoma, caused extensive damage to buildings in the city. Storage tankers are routinely surrounded by containment moats capable of holding the tank contents should a rupture occur. Although no damage to storage tankers was reported, several pipeline operators shut down activities. Enbridge reported that it had launched an emergency response plan to check tanks, pipes, motors, pumps, and other equipment.

Officials determined that water-injections wells, and not fracking, were the main cause. In response, State officials have ordered nearby water injection wells to be shut down, but seismic geologists note that it may take years before the incidence of major quakes related to water injection subsides.

The future

The industrial internet of things (IIot), is growing at a tremendous clip. According to Cisco, there are currently 25 billion smart devices connected to the internet. By 2020, that number is expected to double to 50 billion.

IIot holds great promise for optimising unconventional production. Inexpensive sensors can be used to monitor stimulation and production in real time, allowing operators to fine-tune every aspect of the value chain through ‘big data’ analytics. Before that can happen, however, bottlenecks need to be eliminated. Getting swaths of information from a plethora of smart gauges back to HQ where it can be crunched by algorithms is a difficult undertaking. Unless there is a pre-existing internet within calling range, connectivity can be dicey; bandwidth on cell networks is limited, and satellite links are expensive. In addition, outdated corporate IT systems often cannot handle the load imposed by big data. Finally, all innovation comes with a price tag; IT software and hardware upgrades can run in the tens of millions of dollars.

Fortunately, barriers are being addressed. Thanks to innovation in other sectors, the O&G industry can take advantage of exponential advances in communications, software and hardware. In mid-2015, BP announced an agreement to license GE software that will connect all of BP’s oil wells to the internet in order to optimise production globally. It costs an average of US$3 million per week when an offshore well goes down. BP, which has 6000 producing wells around the world, plans to capture, store, contextualise and visualise data in real time in order to drive efficiency and performance.

What will the longer-term future bring? ‘Code halo’ is a term that is used to describe the digital information that surrounds people, organisations and devices. It is generated by clicks, swipes, views, interactions and transactions that generates a ‘virtual self’ made of code. Individuals have them as consumers; GE is now working to extend the concept to both machines and subject-matter-experts. “You could have a virtual best operator that helps you understand how to achieve better uptime for your assets, regardless of where they are,” says Ashley Haynes-Gaspar, the general manager for Software & Services at GE Measurement & Control. “It would be like a digital twin.”

In conclusion, while the unconventional sector cannot control the price of oil, it has proven over the last two years that it can use innovation and technology to not only survive, but also to thrive in adversarial market conditions.

This article was originally published in Oilfield Technology magazine. The receive your free copy, click here.