The enormous quantity of natural gas in storage is pressing the limits of storage facilities to the max.
The main driver of the current oversupply stems from the great successes operators have realized in the numerous shale gas plays.
But today’s surplus has a way of becoming tomorrow’s shortage.
If there’s a better approach to wrest the gas from these wells, there’s no time like the present to get with program – and that’s what is happening in the United States, including the mid-continent.
The majority of shale gas wells are completed via horizontal laterals off the vertical wellbores. Early on, horizontals were deemed the way to go from an economic standpoint.
Operators drill the lateral legs into what is considered to be the best horizon as determined by well logs, core and seismic data. The lateral sections are placed and evaluated using relatively simplistic technologies, such as gamma ray and mud logs.
Shale beds are notoriously low permeability rocks, meaning they ordinarily need a hydraulic frac stimulation to be economic.
“With hydraulic fracture stimulation, you’re providing a conduit to effectively increase the h of kh (horizontal permeability) and a method for the gas to escape,” said AAPG member Camron Miller, senior geologist at Schlumberger.
“The goal is to maximize reservoir contact through hyudraulic fracture stimulation, which should maximize gas drainage,” he said. “The more free gas that exists, the higher the IP (initial production) will be.”
Miller presented a paper on “Horizontal Well Planning for the Woodford Shale and Other Gas Shales in the Mid-Continent” at the recent Mid-Continent Section meeting in Tulsa.
This free gas is only part of the story.
Shales also harbor adsorbed gas attached to the surface of the organics in the shale, and sometimes to the shale grains themselves.
“It’s important to have a truly strategic hydraulic fracture stimulation to contact as much reservoir as possible so you can produce the free gas, reduce the pore pressure and kick-start the production of desorbed gas,” Miller said. “There may be a lot of adsorbed gas, and it requires lower pressure to release it from the organics.”
Operators naturally are attempting to stay in the better part of the reservoir rock with the drill bit. But reservoir characteristics can change significantly along a lateral of maybe 3,000 feet – and some changes may be virtually undetectable with the ordinary gamma ray and mud log tools.
“These changes need to be addressed in completion design,” Miller said.
“You need to account for changes in reservoir characteristics, such as changes in mineralogy, natural fracture density and orientation, changes in stresses,” he emphasized. “One of the most important things is to identify and avoid perforating near faults.
“Borehole images are an ideal measurement to run in these horizontal wells,” Miller continued. “You can capture images while drilling to look at real time images and stay in the zone, or wait until right after drilling the well when you can convey the imaging tool on the drill pipe.”
Miller noted that borehole imaging provides such high-resolution images that it’s been said they create a core-like image – at a much-reduced price.
Borehole imaging in the horizontal leg allows the opportunity to take measurements along the length of the lateral to identify when/where the characteristics are changing – and to account for these changes in the completion design.
The images provide a qualitative indication of mineralogy and allow the interested party to identify, characterize and define the orientation of bedding, faults and fractures.
“The key point is to design strategic-type hydraulic fracture stimulation based on what the reservoir is telling us,” Miller noted.
In planning the well, data acquired in the vertical hole can determine which layer has the better reservoir and mechanical properties for lateral placement. Drilling direction is determined based on the local stress regime.
In most shales, the target intervals will exhibit high silica and low clay content, according to Miller. Some shales have significant carbonate content where the target would be high silica and/or carbonate and low clay content.
“The zones with low clay content tend to have the better reservoir and mechanical characteristics we want,” Miller said. “They have better porosity and permeability, and that’s where the gas is stored.
“They are the rocks with the lower fracture closure stress and higher Young’s modulus (a measure of the elasticity of a material), so we’ll be able to break them during hydraulic fracture stimulation,” he noted. “More importantly, these zones will stay open longer with less of a tendency to embed or crush proppant.
“That’s huge,” he exclaimed.
Miller noted a geochemical tool being used in the vertical wellbore to help quantify mineralogy also is a highly popular application to evaluate the potential of gas shales and where to place the laterals.
There’s actually a sort of arsenal of tools to attack these rocks.
“Recently we’ve been using advanced sonic tools to determine a more representative stress profile that accounts for laminations within the shale,” Miller said.
“It also can be used along the laterals,” he continued. “It can be run in cased hole so clients can obtain an advanced analysis and don’t have to pay rig time.”
The bottom line appears to be that measurements taken with technology more sophisticated than, say, the standard gamma ray or mud log are highly beneficial to plan completions in the shale wells.
Miller noted, for instance, that it’s fairly typical if an operator with a 3,000-foot lateral decides to implement at least 10 frac stages and places them every 300 feet.
“Using borehole images you see that the reservoir characteristics change significantly in a short period of time,” Miller said. “In fact, we’ve seen numberous examples where up to a third or more of the perfs were not contributing anything to production.”
He emphasized, however, that operators are doing a really good job and making a lot of money right now using a low-tech approach.
“I’m just trying to ask could we be doing better – and how much better,” he said.
“I think the answer is yes – if we plan completions better by taking measurements along the length of the lateral.”