Setting the Stage for Optimal Well Spacing Performance
Data Science & Analytics

Setting the Stage for Optimal Well Spacing Performance

Rosemary Jackson  •  

Stage design, the incremental placing of wells in a cube or well pad, includes decisions focused on well spacing and economic analysis. allows for capital efficiency and well spacing options to be explored through integrated applications that address the geomechanical aspect of understanding the stress regime along the well-bore trajectory and the operational aspect accounting for friction, the perforation pressure drop and stress shadow.

Cube development challenges the upstream oil and gas industry with ongoing capital efficiency issues around one of their most capital-intensive processes, drilling wells in a complex pad. Unconventional shale reservoirs are geology dependent. Well spacing in one area doesn’t necessarily provide insight into even the neighboring area. And the tight spacing needed to optimize extraction means capital expenditure can be high.

Science Direct concludes, “production performance and economic analysis in each area must be the sole deciding factor behind choosing the optimum stage spacing.” But how do you determine and estimate production performance at differing pricing options? How do you determine the ideal subsurface area to contact and at the same time minimize or utilize fracture interference?

Richard Gaut, CFO of, responds to the economic side, “The way you valued shale drillers before 2014 was based on their EUR. Where estimates would point to drilling, say, 9 wells in the future. I only need to drill one now to hold that acreage valuation. That’s how your stock was traded. It was considered a sure bet.

The behavior this incentivized was, I’ll spend cash flow, raise more money, borrow more money—because the more land you have, the more under locations you have and you can increase that EUR number.”

World Oil analysis: Oil price crash of 2014 and 2020

“After the price crash in 2014 and then in 2020, shale drillers under delivered on the investment money that was borrowed based on the premise that those 9 wells would bring in a certain cash flow. Because of that the paradigm for investment had to change. The metrics that the stocks are now judged on are not EUR. They’re based on cash flow because these companies have failed to deliver what their forecasts were. The only tool that investors have is looking at actual cash returns.”

That’s the cube problem. Because of parent/child and vertical interference, the volumes surrounding the drilled wells aren’t always as anticipated using the older EUR and type curve calculations.

“With unconventionals, there really hasn’t been a very convincing EUR strategy yet,” Troy Ruths, CEO of urges, “We need to factor the geomechanics into the capital efficiency plans for these shale wells. We worry about parent child problems but really we should be worried about how fast we’re using up the volume of rock that we’re developing. We need to make sure that we’re proceeding in a cash efficient way because you’re not necessarily putting wells between these other wells later. We’re hoping we can do it, but we need to do the full cube analysis to pull the most oil and gas and money out of the acreage.”

Stage design relies on a specific productivity model for shale. The image below, drawn from the cover of Dr. Mark Zoback’s text, Reservoir Geomechanics, highlights the several geomechanical aspects of the decision-making process in determining well spacing and placement in the cube.

Ruths discusses the model:

“Let’s take a look at this piece of the cube. What’s driving production? This image summarizes your productivity model for shale. There’s two main parts to this picture. The first is propped hydrofrac areas, those are these big blue discs and are emerging from the stimulation of the perforations in the well bore. Then you have all of the small multi-colored discs. These are the shear fracture network which is the microseismic data when you hear as the rock cracking during the frac job. You can think of these multi-colored surface areas connecting together, so that a hydrocarbon here will drain into the propped large, blue colored hydrofrac and move to the well bore.

“Let’s think about what affects this cubic meter of rock.

“You can think about the propped hydrofrac area that we create that with our stage design. Those variables are going to be your clusters/ft that’s cluster spacing, your proppant per cluster, fluid/cluster, your perf diameter which has a very strong effect on your ability to create hydrofractures. And your stress shadow which is timing and sequencing.

Stage design can have a dramatic effect on your productivity in this unit volume because these are all the variables we can change. The other thing we can change is how much fluid we’re putting in and that will allow for further stimulation of the shear fracture network. But at the same time, you’re just sort of given whatever you’re given there.That is a property of the rock at that point. You can’t create more shear fracture area, it just is, based on all the tectonic forces that have shoved that rock and broken that rock down into the ground.

The last piece is the reservoir quality. All of these planes, blue and multi-colored, are in contact with the reservoir. They’re permeable planes to the reservoir. So, your common things like saturation of oil, water and gas, your porosity within the matrix right next to the permeable planes, and then the permeability into that matrix affect the movement. You can imagine each of these planes has a matrix that drains straight into them. And that’s what we produce.

When you think of the total production that you’re getting from this unit cube, it all comes down to creating surface area, connecting that surface area up and then draining that into the well bore.

“You can change these variables to increase your propped frac area. You can also get production with only one hydrofrac plane in there. You can get production from the shear fracture network.

“And then the last is touching different reservoir quality.

“Some of the latest stuff we’ve been working on is understanding and looking at the extraction which is measured in barrels per cubic foot. We can think about the different reservoir layers and what might be driving the different productivity. Is it reservoir quality? Is it having a lot of shear fracture area? Or is it something you’re doing with the hydrofracs?

When you think about your capital efficiency and stage design, you need to think about all these 3 things in combination to drive productivity. That’s important because you could be spending a lot of money on hydrofracs but it’s only contributing 20% of the variances in production. When other variances in production are coming from shear fracture differences in reservoir quality. There’s definitely a different abundance in natural fractures. We know this because we’ve done image logs and we have microseismic data.

“And we also know that reservoir quality changes within the shale interval. That has a dramatic effect on your production. When you think about your stage design you need to put it in context of the full geomechanical model.”

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