Posted on 05/20/2015 4:41:46 AM PDT by thackney
Bakken production will keep growing, albeit at a slower pace, and the Eagle Ford still has running room within high-return portions of the play, according to a recent analysis by Wood Mackenzie.
The Bakken and Eagle Ford together produce just over 2.5 million barrels per day of oil, or nearly two-thirds of U.S. tight oil production.
Higher oil prices in the 2013 to 2014 timeframe spurred operators to drill not only in the core of the Williston Basin, but in the fringe and speculative areas. This included areas along the Montana-North Dakota border, the northern most part of the play near the Canadian border, and the southern portion of the Williston Basin.
Operators have responded to the decline in global oil prices from over $100/bbl last year to around $60/bbl today by reducing rig counts and retrenching drilling activity to the core Bakken area, Jonathan Garrett, principal analyst for Wood Mackenzie’s Lower 48 Upstream group, told reporters at a media briefing in Houston last week. In the early third quarter of 2014, the rig count in the Bakken was 185 to 190 rigs. Today, 86 rigs are operating in the Bakken.
The rig count is down across U.S. Lower 48 plays, including the Bakken play. Early in last year’s third quarter, between 185 and 190 rigs were operating in the Bakken. As of May 15, that number had declined to 84. However, the decline in drilling rig counts has not occurred evenly across the Bakken.
In Divide County on the northern fringe of the Bakken – where the Bakken is thinner and pressure isn’t there versus deeper parts of the play – the rig count is down about 70 percent due to the play’s more challenging economics. But in McKenzie County in the play’s core – home to the more prospective subsplays, the West Nesson and the Nesson Anticline – the rig count has not dropped off as significantly as other areas, Garrett noted.
The biggest Bakken wells in terms of production lie in the eastern fringe of the Bakken in the Parshall-Sanish, Fort Berthold and Nesson Anticline subplays. Wood Mackenzie anticipates that estimated ultimate recovery (EUR) for these wells this year and in early 2016 will likely outperform EUR estimates due to the retrenchment to the core and operators attacking their best rocks first, Garrett said.
An example of this shift is Continental Resources. Last year, the company said it would drill an average well in the Bakken of 600,000 barrels of oil equivalent. Due to low oil prices, Continental recently said that it would only drill 800,000 barrel wells or greater.
Despite calls that Bakken production will roll over, Wood Mackenzie believes that the Bakken will see a modest increase in production this year. In 2014, the play produced 1.1 million barrels per day (bpd) of oil. Wood Mackenzie now estimates the Bakken will produce just over 1.2 million bpd in 2015, a change from initial estimate made early last year. Wood Mackenzie anticipates that EURs in 2015 and the first half of 2016 will likely outperform the EUR base case by 20 percent because of companies’ highgrading their activity, Garrett said.
Wood Mackenzie expects to see the biggest future production gains in the West Nesson subplay. By 2020, Wood Mackenzie anticipates the West Nesson subplay will be “head and shoulders” against other subplays in the Bakken. While other subplays like the Parshall-Sanish are dominated by a few players, West Nesson is unique in that 12 to 13 good-size operators are drilling fantastic wells there, which will lead development over the next five years.
Garrett said that Wood Mackenzie had been watching to see if May West Texas Intermediate averaged less than $55.09/bbl. That would have been the fifth consecutive month in a row that WTI averaged less than that price threshold, and would have meant that operators would have been paying an effective state tax rate of 5 percent, not 11.5 percent. That is not likely to occur due to the rise in WTI and North Dakota’s governor recently amending the law – an amendment to the state’s oil tax rate framework. But the potential effective tax rate drop – and activity spurred by oil prices closer to $60/bbl – meant that Wood Mackenzie’s forecast of a modest production increase in 2015 would have been supported.
Plenty of Running Room Left in Eagle Ford Sweet Spots
The firm sees plenty of running room left in the Eagle Ford play in the high-performing Edwards Condensate and Karnes Trough subplays, Garrett said. The place of drilling in the play is cooling, but the performance of wells is improving over time in terms of initial production rates and EURs for the many different subplays.
Performance of Eagle Ford production continues to rise due to advancements in completions, better lateral placement, faster pump rates, and a shift from open hole completions using sliding sleeves to plug and perf with cement liner.
The proppant usage per lateral foot and fluid or water use per lateral foot in the Eagle Ford is “head above shoulders” above the Wolfcamp, Bakken and Niobrara, Garrett commented. The intensity stems from operators realizing that using more of a cheaper proppant – in the case of the Eagle Ford, natural white sand from Wisconsin and Minnesota – was a better option than a synthetic proppant. The industry has been “ahead of the curve” in the Eagle Ford in that regard.
On the fluid side, operators also have found more production success by shifting from a wider gel frack to a smaller but denser slickwater frac. Slickwater has outperformed gel in terms of cumulative production, Garrett noted. However, slickwater also requires more water; in a year or two, Eagle Ford water usage per lateral foot will be closer to figures seen in the Wolfcamp.
Eagle Ford operators also got up to speed quickly by putting a great fraction of wells on pads faster than in other plays. The ramifications of pad drilling will result in more savings and efficiencies in drilling, pressure pumping, supply chain and infrastructure.
http://www.thebakken.com/articles/711/the-slickwater-story
...Slickwater fracks were used before gels and high viscosity fluids became the industry norm for conventional and unconventional fracking designs, but the simple design of a slickwater frack has proven to produce a more complex fracture network in the middle Bakken formation.
...The basics of the method involve water combined with a polyacrylamide friction reducer. The slickening agents reduce the friction of the water in the pipe and the viscosity of the fluid. Because the fluid is less viscous and the water is lighter, more volume is needed to carry the same amount of proppant to effectively prop open the fracture networks responsible for draining the reservoir. Higher rates of pressure are also required to move the water. Pumping rates of 100 barrels per minute are common—a much higher rate than other unconventional fracturing pumping method requirements. The high pressure needed to perform a slickwater frack also helps to stimulate more rock and create more fractures. The absence of gel also allows for a quicker and easier placement of proppant into the fractures allowing the hydrocarbons to flow back quicker.
Of all the concerns about slickwater treatments, the greatest is the water volume required. Because the Williston Basin is situated in a geographic region with an abundant water supply, operators are able to deploy the method without incurring high water costs. The amount of water needed to perform a slickwater frack job typically exceeds 4 to 8 million gallons. In some cases, the quantity of pumping trucks used to inject the pressurized water into the wellbore needs to be doubled. Because the fluid treatment doesn’t rely on additives, slickwater fracks are more conducive for produce and flowback water recycling efforts, the authors also wrote....
Fracturing Fluids 101
http://www.hexionfracline.com/fracturing-fluids-101
There are primarily three types of fracturing fluids currently used. These are water frac or slick water, linear gel, and crosslinked gel. All three of these frac fluids have different properties and applications.
Water frac is water containing a friction reducer and possibly a biocide, surfactant, breaker or clay control additive. This fluid has a low viscosity of 2 – 3 cP, which requires a high pump rate to transport proppant. Small proppant size like 40/70 is common with this fluid due to its low viscosity. Water frac is the least damaging to the proppant pack of the three frac fluid types and it is commonly used in gas wells.
Linear gel is water containing a gelling agent like guar, HPG, CMHPG, or xanthan. Other possible additives are buffers, biocide, surfactant, breaker, and clay control. This fluid has a medium viscosity of 10 – 30 cP, which results in improved proppant transport and wider frac compared to water frac fluid. Medium proppant size like 30/50 is common with this fluid. Linear gel is more damaging to the proppant pack than water frac and it is commonly used in both gas and oil wells.
Crosslinked gel is water containing any of the gelling agents used in linear gel and a crosslinker like boron (B), zirconium (Zr), titanium (Ti) or aluminum (Al). Other possible additives are buffers, biocide, surfactant, breaker, and clay control. This fluid has a high viscosity of 100 – 1000 cP, which results in better proppant transport and wider fracs compared to linear gel frac fluid. Large proppant sizes like 20/40 and 16/30 are common with this fluid. Crosslinked gel is more damaging to the proppant pack than linear gel and it is commonly used in oil and high liquid wells.
Other less common frac fluids include gelled oil, gelled acid, foamed oil with nitrogen, foamed water with nitrogen or carbon dioxide, and gelled LPG.
you placed some comprehensive explanation of frac fluids and frac techniques here that is likely to befuddle a layman. but if repeated enough it might stick.
BTW, reason Continental is saying it will only take 800mbo wells rather than 600mbo wells is not just where they are drilled but also how they are completed.
One can get higher recoveries if one completes the well differently.
A number of those so-called marginal areas of Eagleford and Bakken are really just not as prolific as the core. Doesn’t mean they too cannot produce enough to be commercial if one fracs the wells differently.
1. more stages
2. more fluids
3. longer laterals
4. Slickwater fluids
In time, multi-laterals(more than one lateral in a well) will rule the day too
Yeah, the tech stuff is not for everyone, certainly.
But since the differences in cost was discussed in the original, I thought I share what they were talking about.
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