Impacts of dense drilling on NG production


#1

I am sure some if not all who frequent this forum read the Wall Street Journal story discussing negative impacts of lots of wells in close proximity on oil production. In a nutshell, the story indicates the “baby” wells are having a negative impact on the initial well for an area (that is a very crude way of saying it I am sure). For those with natural gas production only, would such be the case as well. Too many wells in a close proximity negatively impacting flow of NG? The indication was that flow was not only impacted but long term recovery potential. In other words, less of the available oil would be recovered for the life of the well.


#2

Wade Caldwell just posted some articles on the same topic. I think they are under the NARO Category. The quick answer is that “it depends”. Some reservoirs are more impacted than others. It depends upon the rock properties of the reservoir and how close the wells are drilled. Also, how long the time frame is from the parent to the child well and whether they pressure up the parent well before they frac the child wells.


#3

Thank you for the response. In my case, family property is in the Alpine High area just a few miles southwest of Toyah.


#4

Remember just because there are 10 holes at the surface near each other, the bottoms may be extremely far apart. The best thought I can give is think of the points on an umbrella. The surface might look like the tip of the umbrella, under the ground might look like where the clothe ties to the expandable frame…most of these wells I am guessing are not vertical wells, but horizontal and the end point might be as far as two miles away from the surface entry point. Or potentially they could be a different depths. Oil oil wells at 2000ft down might be next to a gas well that is 10-20,000 feet deep.


#5

HGS General Lunch- Engineering Perspective of the Oil Industry – What is the Correct Inter-well Spacing? | Houston Geological Society .

Houston Geological Society is having a lunch meeting with a speaker addressing that very issue of spacing.


#6

Bad news sells, right? In light of the general insanity of extrapolative expectations that permeates the mineral space, buyer and seller alike, IMO some bad news is probably a good reality check.

There is a point where you just can’t keep going back to the (proverbial) well. You have a giant sheet of cookie dough, you can only cut out so many of your snowflake shaped cookies out of the sheet before they overlap. Oil (or gas) in place is finite. Even in micro or nanodarcy reservoirs, given enough time, point A and point B will be in communication. If you drill too many wells they will fight over the same resource. If you drill wells a certain distance from each other, when you frack a new well the stimulation may get affected by the drainage from the older well. If you base your well expectations on observations of a single well with no offsets, you may find that you have overestimated subsequent well performance.

That’s the theory. As M.Barnes says, it depends. On spacing, on permeability, on thickness/landing target separation. In other words on Basin/zone and operator. I have my own opinions on where or how much it depends, but am just random goof on the internet and not some WSJ reporter, so they probably don’t mean much.

That said, I would not be worried about this at all on the Alpine High. Apache is going to have a hard enough time drilling enough wells to hold acreage without worrying about deciding to pack in a zillion wells in a single unit.


#7

WSJ Consider the source I wouldn’t give it much attention


#8

How about the CEO of Schlumberger then? Part of the issue here is that it’s a new technology - hopefully the lessons from the Eagle Ford and the Midland Basin are productively applied in the Delaware Basin.


#9

I hope you will post a review/synopsis of the presentation.


#10

However, the main challenge in the Permian going forward is more likely to be reservoir and well-performance, as the rate of infill drilling continues to accelerate.

For a resource base where production is entirely dependent on fracture propagation and fracture coverage to drain the reserves, we have yet to understand how reservoir conditions and well productivity change as we continue to inject billions of pounds of proppant and billions of gallons of water into the ground each year.

Still, what is already clear is that unit well performance, normalized for lateral length and pounds of proppant pumped, is dropping in the Eagle Ford as the percentage of child wells continues to increase.

These production headwinds have, in recent years, been overcome by drilling longer laterals and pumping ever greater volumes of sand and water.

However, the use of these remedies seems to be coming to an end, both from a technical and commercial standpoint.

Today, the percentage of child wells being drilled in the Eagle Ford has already reached 70% and, in the 3-year period since this percentage broke the 50% level, we have seen a steady reduction in unit well productivity.

In the Midland Wolfcamp basin of the Permian, the percentage of child wells has just reached 50%, and we are already starting to see a similar reduction in unit well productivity already seen in the Eagle Ford.

This suggests that the Permian growth potential could be lower than earlier expected.

https://www.slb.com/news/presentations/2018/2018_0904_kibsgaard_barclays.aspx

The application of measurement technologies to improve subsurface understanding, and fluid technologies to better control fracture propagation conformity, could potentially improve the observed trends.

However, deploying these technologies will require a significant mindset change throughout the industry, and a willingness to increase investments to overcome the growing reservoir challenges.


#11

SLB CEO: Everyone needs to use more SLB technology.


#12

:grin: … well, that is his job


#13

Off topic … did you fly F100’s?


#14

Nope I drove them - Ford F100 pickups (: