Horizontal wells typically produce far more oil and gas per well than vertical wells because they expose much more of the reservoir to the wellbore, but they cost more to drill and complete and decline faster in the early years. Vertical wells still make sense in thick, conventional reservoirs or exploration settings where a lateral adds cost without adding meaningful production. The right choice depends on reservoir geometry, permeability, and how a project’s cash flow is expected to behave over time.
TL;DR:
- Horizontal wells produce 2.5 to 7 times more than vertical wells and supplied 92% of Lower 48 natural gas and 94% of its oil.
- Steep declines in the first year or two require continued drilling; more than 11,700 of roughly 15,000 U.S. wells drilled in 2024 were horizontal.
- Compare lateral lengths, fracture stage counts, and spacing with formation benchmarks; extra stages eventually yield diminishing returns, while close wells can interfere.
- Investors should compare decline assumptions with similar wells and include completion intensity, pad level water and logistics costs, and tax treatment in cash flow estimates.
Table of Contents
- How is a horizontal well drilled and completed?
- What is a vertical well and when does it still make sense?
- Horizontal vs vertical wells: productivity, cost, decline, and footprint
- What technical factors decide whether a horizontal well outperforms?
- What these differences mean for investors and asset owners
- A pragmatic way to screen horizontal vs vertical proposals
- Fieldvest: an adjacent route to vetted producing assets
- FAQ
- Sources
How is a horizontal well drilled and completed?
A horizontal well starts out drilled like any other well: straight down through the surface formations. At a planned depth above the target reservoir, the drill string builds a curve, gradually turning the wellbore from vertical to near-horizontal so it can travel sideways through the productive layer, or pay zone, for a long distance.
Lateral lengths commonly run from a few thousand feet to over 10,000 feet, and some modern laterals in plays like the Bakken extend to 10,000 to 15,000 feet, carrying far more proppant and fluid than earlier designs did, which has driven major production gains in that formation, according to a JPT analysis of Bakken well performance. Once the lateral is drilled, operators run multistage hydraulic fracturing, isolating sections of the pipe and fracturing the rock around each one separately.
- The curved section, called the kickoff, transitions the well from vertical to horizontal before entering the pay zone.
- Multistage completions create dozens of isolated fracture zones along a single lateral, multiplying contact with the reservoir.
- This method has become the standard approach for shale and other tight formations where oil and gas are spread thin across low-permeability rock.
What is a vertical well and when does it still make sense?
A vertical well is drilled straight down to the target formation, with casing set in stages as the hole deepens and cemented in place to seal off different rock layers. Completion is comparatively simple: a single zone, or a small number of zones, is perforated and stimulated without the extended lateral section or the dozens of fracture stages a horizontal well requires.
That simplicity keeps upfront drilling and completion costs lower, which matters in conventional reservoirs where oil or gas sits in a thick, permeable layer that a vertical wellbore can drain efficiently on its own.
- Exploration wells often go vertical first, since the goal is confirming what is downhole, not maximizing output from a known formation.
- Thick, high-permeability conventional reservoirs can produce economically without the added reach of a lateral.
- Some offshore and legacy field developments still favor vertical or near-vertical wells where reservoir geometry doesn’t reward a long lateral.
Horizontal vs vertical wells: productivity, cost, decline, and footprint
The productivity gap between the two well types is the headline difference. Horizontal wells typically achieve 2.5 to 7 times higher production than vertical wells because the extended lateral reach increases contact with the productive pay zone, according to SPE research on multistage horizontal well design. Horizontal wells also accounted for 92% of natural gas in the Lower 48 by late 2024, per EIA reporting on drilling trends.
94% of Lower 48 oil output now comes from horizontal wells, a shift driven almost entirely by the combination of long laterals and multistage fracturing, according to the same EIA analysis.
The trade-offs run deeper than the headline multiplier:
- Horizontal wells cost more to drill and complete than verticals, but the SPE research cited above found that ROI can still favor horizontals once completions are optimized, since they unlock resources a vertical well couldn’t reach economically.
- Horizontal wells, especially hydraulically fractured ones, tend to decline faster in their first year or two than vertical wells, which changes how quickly a project needs new drilling to sustain output.
- Multiwell pads let operators drill several horizontal laterals from one surface location, shrinking the footprint per well, though the pad itself concentrates water handling, tanks, and pipeline infrastructure that need their own planning.
That decline behavior isn’t a side note. More than 11,700 of the roughly 15,000 new U.S. wells drilled in 2024 were horizontal, largely because sustaining basin-level production now depends on continuously replacing output lost to steep early declines, per EIA data on 2024 drilling activity.
What technical factors decide whether a horizontal well outperforms?
Lateral length and stimulated reservoir volume are the primary levers. A longer lateral touches more rock, and more fracture stages along that lateral create more pathways for oil and gas to flow into the wellbore. But the relationship isn’t linear forever.
Adding fracture stages produces diminishing returns past a certain point, and that optimal stage count shifts with reservoir permeability and the oil price assumptions used in the economic model, according to SPE simulation studies on multistage design. Wells spaced too close together also start competing for the same reservoir volume, a problem known as well interference, which can erode the production gains additional laterals were supposed to deliver.
- Longer laterals generally increase the stimulated reservoir volume and early production, up to a practical limit set by drilling and completion logistics.
- Extra fracture stages help until the reservoir’s permeability can no longer support the added complexity, at which point returns flatten.
- Tight well spacing can trigger interference between laterals, cutting into the output each well was designed to deliver.
Pro Tip: Ask an operator for their fracture-stage and spacing benchmarks by formation, not just a single well’s results, since one well rarely represents what the next one will do.
What these differences mean for investors and asset owners
A horizontal well’s higher initial production and faster decline together reshape a project’s cash-flow timing. Early distributions can look strong, but sustaining them at the basin level requires operators to keep drilling, which affects long-term capital spending plans, as EIA’s analysis of drilling cadence and coverage of that data in Oil & Gas Journal both point out.
Before committing capital, it helps to ask for an operator’s decline curve assumptions, how they benchmark completion intensity against comparable wells, and what pad-level water and logistics costs look like beyond the per-well numbers. Reviewing how intangible drilling costs factor into a project’s early tax treatment also clarifies how the cash-flow picture and the tax picture interact.
A pragmatic way to screen horizontal vs vertical proposals
Horizontals earn their cost in thin, low-permeability formations where reach matters more than simplicity; verticals still win in thick, conventional reservoirs or early exploration where a lateral adds expense without adding much oil.
When screening a proposal, check the decline curve against comparable wells in the same formation, confirm the lateral length and stage count match what similar wells have used successfully, and ask how the operator handles well spacing to avoid interference.
— Sharif
Fieldvest: an adjacent route to vetted producing assets
Weighing horizontal against vertical economics is exactly the kind of due diligence we built our marketplace to support. We provide a marketplace connecting investors with energy project operators and display project materials, including decline assumptions and completion benchmarks, to help compare proposals on the dimensions that matter. If you want to see how a producing asset’s tax treatment and cash flow could fit your own numbers, our tax deduction calculator is a good place to start, or visit Fieldvest to browse current opportunities.
FAQ
What is horizontal drilling in oil and gas?
Horizontal drilling turns a wellbore from vertical to near-horizontal once it reaches the target reservoir, letting it travel sideways through the productive layer for thousands of feet. This dramatically increases contact with the pay zone compared to a vertical well, which is why horizontal wells now account for the large majority of U.S. oil and gas production.
What are the three types of wells?
Wells are generally grouped by trajectory: vertical wells drilled straight down, directional wells drilled at an angle to reach a target offset from the surface location, and horizontal wells that curve to run sideways through the reservoir. Each type suits different reservoir shapes and surface constraints.
How far can you horizontal directional drill?
Lateral lengths in U.S. shale plays commonly range from a few thousand feet to more than 10,000 feet, with some laterals in formations like the Bakken reaching 10,000 to 15,000 feet. The practical limit depends on drilling equipment, reservoir geology, and completion design rather than a fixed industry cap.
What are the three types of drilling?
Drilling methods are typically described as vertical, directional, and horizontal, reflecting how much the wellbore’s path bends away from straight down. Horizontal drilling is a specific form of directional drilling where the well is turned fully sideways to maximize reservoir contact.
Do horizontal wells always produce more than vertical wells?
Horizontal wells typically produce 2.5 to 7 times more than vertical wells in the same formation because of their greater reservoir contact, according to SPE research. In thick, conventional reservoirs with strong permeability, however, a vertical well can still produce economically without the added cost of a lateral.
Sources
- Design optimization of multistage horizontal wells (SPE/OnePetro proceedings abstract)
- Rapid declines from horizontal wells require more drilling to sustain production (EIA Today in Energy)
- Analytical study examines production of multistage horizontal wells in the Bakken (JPT / SPE)
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