Square One, Part 4 - Drilling and Completion Set the Stage for Hydrocarbon Production
Thursday, 03/02/2023Published by: Jacob Arrell rbnenergy.com
Another good article from RBN. I suggest that you use the link below since the graphs do not cut-and-paste.
Oil and gas production in the Shale Era is a refined, controlled process — and a far cry from the early days of wildcatting a century ago. Modern drilling typically involves multiple wells on a single well pad, with each well going through a four-stage process to produce hydrocarbons that are then separated into distinct components. In today’s RBN blog, we look at how drilling-and-completion techniques have evolved over the years, from old-school vertical wells to the highly complex strategies targeting shale areas today, and how they set the stage for hydrocarbon production and recovery.
Our series of “Value Chain 101”-style blogs is designed to provide a better understanding of the journey those all-important hydrocarbon molecules take from the production site to their respective downstream markets (see Figure 1 below). Part 1 introduced us to how reserves are calculated and the types of companies that operate in the upstream sector, Part 2 walked us through the highly detailed leasing process, and Part 3 provided a primer on seismic surveys and well-site preparations. Once those steps are complete, the focus shifts to getting a well drilled, completed and in production.
Advances in technology have allowed drilling strategies to become much more complex over the years, moving from vertical drilling of individual wells to the highly sophisticated strategies for developing large shale plays today. But before we get into too much detail about how those strategies are intended to work, we need to start with some of the basics about the drilling-and-completion process.
The production lifecycle of a well can be generally categorized into four main stages: drilling, completion, production/separation and (eventually) plugging/abandonment. We’ll look at those first two stages today. Whether it’s vertical or horizontal drilling, the first step begins with the well itself. Once a location has been specified — following the detailed seismic surveys and well-site preparations we discussed in a previous blog — and the drilling rig and associated equipment has been delivered to the site and set up, the drilling can begin. After the drilling apparatus reaches a safe area — typically an area below the deepest aquifer present to avoid contamination — a steel pipe is inserted. This new pipe, known as the casing string, is pushed into the well and cement is pumped in, out the bottom, and back up around the outside of the pipe between the wellbore and the casing, effectively sealing off the well from any outside interference (i.e., water) and securing the casing string to the formation, thereby maintaining the stability of the newly drilled hole in the ground.
There are multiple levels of casing that will go into a well, with the walls getting progressively smaller in diameter as the well’s depth increases (see Figure 2 below). There are many different names for these casings, notably moving from thicker conductor and surface casings to intermediate casings to the thinnest, and final, production casings. Multi-layer casing is needed because areas near the surface typically contain looser sediment that is much more prone to cave-ins and thus requires stronger (thicker) walls to protect it.
As we discussed in Tales of the Tight Sand Laterals, vertical drilling is relatively uncomplicated. You do the seismic, mark your “X” on the map, send in the rig and drill straight down. If you do that in just the right place in a conventional reservoir of porous rock such as sandstone, it’s like putting a straw into a sponge as it’s squeezed. (It should be noted that lots of people think there are “pools” of oil and gas, almost as if they were in tanks, sitting underground just waiting for someone to tap them. That’s incorrect. The conventional resources are really just soaked into rock that’s not too dense for them to flow if given a way out.) The main risk to drilling for porous formations where large, economically recoverable quantities of oil or gas are located is that if the vertical well misses the high-concentration parts of the formation, you may not find anything, or you may not find enough hydrocarbons to make it worth spending the money to get them to market. When that happens, you’re left with what’s known as a “dry hole.”
Drilling in a shale formation is very different. The shale source rock is extremely dense, more like an old schoolroom blackboard. The concentrations of oil and gas are spread out, and do not easily migrate from one part of the shale to the other, and horizontal shale formations, while nice and wide, are generally not very thick. Up until the Shale Revolution, a vertical well, with just a few feet of contact with the hydrocarbon-rich horizontal formation, could not extract economically useful quantities. That all changed when George Mitchell and his engineers at Mitchell Energy came up with a breakthrough in shale drilling in the 1990s — hydraulic fracturing (also known as fracking; more on that below) was not a new technique at the time, but Mitchell’s team was the first to use fracking to free natural gas from shale and showed that it could be financially viable over the long-term. Fracking to enable the oil and gas to flow was combined with the use of horizontal drilling to get a lot more (sometimes miles) of pipe in contact with the hydrocarbons entrained in the dense rock, and lead to dramatic increases in production.
Horizontal drilling usually begins with a gradual 90-degree turn (see kickoff point in Figure 2) after a well has been drilled vertically to the desired depth in the producing shale formation, although the turn can be more or less than 90 degrees if needed. Horizontal drilling allows the production company to “mine” a seam of oil- or gas-bearing shale (the production zone or pay zone, dark-gray layer in Figure 2) by drilling laterals that penetrate the shale layer horizontally. Needless to say, this approach requires a high degree of precision, as some shale layers can be very thin. (According to our friends at Natural Gas Intelligence, the hydrocarbon producing zone in the Bakken Shale averages 10-120 feet in thickness, Eagle Ford formations are 150-300 feet thick, and the Permian’s formations are 1,300-1,800 feet.) The lateral lengths in horizontal wells can range from 1,000 feet to 20,000 feet (~4 miles), with longer laterals becoming utilized more often over the past few years to improve well economics. The long horizontal lateral creates a large surface area in contact with the rock and potentially allows a lot more oil and gas to flow into the well bore. In addition to the productivity improvement, longer laterals also improve drilling economics because wells are able to tap a wide subsurface range, often from a single well pad, enabling access to large amounts of shale resources from a tight geographic area (see Figure 3 below) and gaining economies of scale. In the Permian, the most prolific unconventional formation in the U.S., the wellbores tend to parallel each other rather than run in different directions. (For offshore drilling it is more common to reach out in multiple directions from a central starting point to minimize platform needs, but in onshore drilling the goal is to uniformly drain a productive formation.)
Compared to vertical-only drilling (cut-away graphic to left in Figure 3), horizontal drilling (cut-away graphic to right) reduces the overall number of well pads, access roads, pipeline routes, and production facilities required. (The pad is the cluster of above-ground equipment that sits on top of the well, including the wellhead, holding tanks, initial processing equipment, and monitoring devices.) And, as we said in Go Big or Go Home, since horizontal wells are generally much more productive than vertical wells, the per-barrel production costs are much lower even though drilling costs are generally higher.
But shale production isn’t as simple as drilling a horizontal well. The hydrocarbons in the pay zone must have a path to the wellbore, too. This is where well perforations come into play. In that process, a perforating gun is lowered into the well to set off a group of shaped charges in a specific section of the well. These explosions create distinct holes or perforations through the well’s casing and cement sheath, creating a pathway for the oil and gas to flow to the wellbore. In shale formations, that process is combined with hydraulic fracturing, better known as fracking, to access the hydrocarbons. After the perforations have been made in a specific section of a horizontal well, a pressurized mixture (generally about 85% water, 14% specialized sand or other proppant, and less than 1% chemicals, according to FracFocus, a fracking chemistry registry) is then directed down the well path, through the perforations, and out into the rock, which forces tiny fractures in the shale to expand and extend to where the hydrocarbons are trapped. (About 20-30% of the water used in the stimulation process flows back up the wellbore, where it can be collected in on-site pits, put into deep disposal wells, routed to an off-site water-treatment facility, or recycled for future use; see Wipe Out! for more.) When the pressure is released, the proppant contained in the fluid keeps the fractures open, providing a pathway for oil and gas to flow into the well. Hydraulic fracturing typically is performed in multiple stages, starting at the far end of the lateral and moving back toward the wellhead as each stage is completed.
These days, with investors still largely focused on capital discipline, producers are extending their laterals, reducing costs, and optimizing their drill plans to extend the productive life of their acreage. As always, the goal is to achieve the lowest cost per barrel over the life of the well. As “unconventional” techniques like horizontal drilling and hydraulic fracturing have advanced to the point where they are now commonplace, they have enabled the use of more sophisticated strategies using complex drilling patterns and tighter well spacing — such as the “cube” approach (see Figure 4 above), the “wine rack” and others — designed to bring large sections of producing acreage online in a shorter period of time. These strategies, which have been implemented in the Permian and elsewhere, are designed to maximize recovery while also realizing greater capital efficiencies from drilling-and-completion operations and surface-treating facilities, enabled by large tracts of contiguous acreage and development at scale, although their overall effectiveness is often met with skepticism.
Once all the drilling and completion work is done, it’s time for those hydrocarbons to start flowing. In the next blog in our series we’ll walk through the different steps in the production-and-separation process, including artificial lift systems, knockout drums, heater treaters and LACT (lease automatic custody transfer) units, and how plugging and abandonment work for wells at the end of their productive life.
these are really well-written articles. Thanks for posting, Skip
You're welcome, Steve. RBN Energy is one of my favorite blogs. It is free to sign up to receive the daily articles.