Your account already exists. Please login first to continue managing your settings.
New fracture designs, integrated workflows, and incremental changes in technology continue to improve the cost effectiveness of unconventional well completions.
“If you’re faced with a gas price you can’t change, you’d better do something about the costs that go into getting that gas out of the ground,” said Kevin Heffernan, vice president, Canadian Society of Unconventional Resources. “Technology has historically played a big role in that, and in today’s world, it’s no different.”
Keeping costs down amid depressed gas prices remains a critical component in drilling and completions operations across the North American shale plays, particularly as the rapid development of shale gas has flooded the market with new supplies, creating a glut that has burdened the domestic commodity’s valuation in the last couple of years, according to a completions and cost control panel moderated by Hefferman at the DUG Canada conference in Calgary, Alberta, June 19.
With today’s large pad operations being compared to a “manufacturing process” or factory, lost minutes on fracture treatments, optimizing transition times between fracture stages, and cost assigned to downtime all must be considered critical components in cost efficiency and control.
More With Less
According to the panel’s consensus, new fracture designs, integrated workflows, and incremental changes in technology continue to improve the cost effectiveness of unconventional well completions.
Tim Pope, stimulation domain manager, Schlumberger Canada, noted that fracturing was once a two-dimensional problem. “If we knew the height, we could design for a certain length,” he said. “Then with the coming of age of microseismic, we realized the earth wasn’t flat. Not only were fractures that were planar not planar anymore, but the ones that were planar were asymmetric.”
Now, Pope said, operators must consider and “worry about things like anisotropic stress properties.”
Integrating geology, geophysics, petrophysics, and geomechanics into an unconventional completion workflow can help optimize hydraulic fracture stimulation results and aid in staging and perforating, driving increases in production. “What’s the upside to this? Not just the added production -- that’s the easy answer,” he said. “Engineering holds the largest upside potential.”
When considering the billions of dollars invested, millions of cubic meters of water, millions of tons of proppant, time, horsepower, and all the things that go into stimulating unconventional wells, which ultimately can be expended on poor performers, an unconventional workflow enables operators to “do more with less” by helping them make informed staging decisions to optimize completions.
“We had to develop unconventional fracture models that allow us to model the hydraulic fracture’s interaction with the natural fracture system,” Pope explained. “We also had to understand proppant transport within these complex fracture wells. Now we truly have a three-dimensional fracture well.”
He pointed to production results from four of the major shale plays in the US. “What’s interesting is that even though there’s been technology applied and stage counts are increasing over time, we see virtually no change in the average production rate. Embedded in these datasets is the fact we have statistical variations in reservoir quality and completion quality.”
Good reservoir quality and completion quality, he said, are what drive production and lead to economic success. For defining reservoir quality, the company looks at hydrocarbon in place, fluid properties, and pore pressure, among other factors. For defining completion quality, the company looks at fracture containment (anisotropic stress), 3-D rock mechanics, the ability to retain surface area, fracture conductivity, and fluid sensitivity.
Citing a case study as an example of conventional versus unconventional workflow, Pope said PDC Mountaineer was able to improve its production by more than 50% while reducing screenout risk in the company’s Marcellus shale operations using Schlumberger’s Completion Advisor workflow and Sonic Scanner.
The operator wanted to optimize horizontal well completions and productivity, so some frac stages were reduced from four perforation clusters to three and intervals were high-graded based on reservoir quality and completion quality indicators, according to Pope’s presentation.
PDC’s production improvement was directly attributed to the identification and selection of optimal perforation locations and staging decisions based on property logs, Pope said.
Understanding that the field is a significantly expensive laboratory is the key to learning how to produce more with less through technology. The best completions model, according to Pope, integrates optimum data, understanding of the reservoir and completion quality, and reservoir-based well placement to mitigate a purely statistical result while reducing equipment footprint and fluid volumes.
David Quirk, technical manager of unconventional resources at Trican Well Service, also discussed fracture design in unconventional cased holes versus open holes using a case study conducted in the liquids-rich Glauconite tight-gas sandstone formation.
He concluded that fractures appeared more planar in the cased hole well, which also had longer fractures with gas rates 36% higher and cumulative recovery 27% higher on a per frac basis for the cased hole at 3.5 months.
After accounting for reservoir pressure differences, the gas rate was 11% better for the cased hole per fracture, according to Quirk’s presentation.
The uncertain price and finite availability of fracturing fluids like guar also can significantly affect completions costs, he said. Guar prices have increased by more than 400% in recent years because of accelerating demand in North American shale plays, which could result in a possible shortage in the fall before the next crop is harvested.
However, alternative options such as using a guar substitute system like carboxy methyl cellulose could help ease supply constraints in the fracture fluid market, and demand could drop significantly, he added.
“When we think about shales in general, these are probably not a perfect environment for repeatability and reducing costs overall,” said Timothy J. Probert, Halliburton president, strategy and corporate development. “Nonetheless, the industry has done a great job in the course of the last couple of years in delivering material increases in productivity and general increases in both gas and liquids production.
“But the world is changing on us, and the economic potential of a number of fields is really in question, particularly dry gas fields, which are being challenged by current pricing. We really have to start to think differently about the efficiency that we bring to the equation [in terms of unconventional resource development],” he said.
Contact the author, Nancy Agin, at firstname.lastname@example.org.