The headline-creating Austin Chalk boom that kicked off in the late 1980s in south Texas provided a badly-needed ray of hope for industry players who had been sucker-punched by downward spiraling commodity prices earlier in the decade.
The brittle, fractured Chalk had long been a challenge to explorers; the key to its successful yet limited run this time around was the implementation of horizontal drilling technology – for the first time, operators oriented their wells laterally at predetermined depths to tap into far more of the pay zone interval than the long-used vertical wellbores.
It was, however, a tough go for directional operators trying to stay on target deep in the subsurface, equipped principally with maps.
Advances in technology and software help “geosteerers” visualize formation dip changes.
Given that horizontal drilling was gaining traction as the go-to technology in various locales, heads were coming together to refine the approach.
And at that time, geosteering soon became the “next new thing.”
The technology basically is a means of steering the drill bit with reference to geological markers. The markers often are the top and bottom of the pay zone, frequently defined via gamma ray or resistivity data.
Today, the relatively new “chromalogs,” which identify rock color, are proving successful as a second data point.
In geosteering, subsurface data are interpreted in real time – or true time, to be more precise – to provide the geologist on the well with the information needed to enable the driller to stay on target in the lateral leg.
This is not for the weak at heart, considering the geologist on the well must continuously make decisions “on the run” as the ongoing flow of downhole data are analyzed. Imagine the weighty responsibility of ensuring that the bit remains in, say, a 10-foot zone for a few thousand feet.
It’s essential to know geologically where the well is at all times.
The payoff from the resulting enhanced reservoir contact is worth it to the operator in a number of ways, including:
- Less oil left behind.
- Higher cumulative production.
Seeing Is Believing
It was inevitable the advantages of geosteering would trigger formation of new companies to specialize in this innovative procedure. One of the first to arrive on the scene was Horizontal Solutions International (HSI), which debuted in mid-1990s.
“All geosteering is data dependent,” commented AAPG member George Gunn, vice president at HSI. “The data get pulsed up from the bit, and you have to analyze that data.
“We depend on the directional drillers/operators to get us the data ASAP so there is no delay in the analysis,” he said. “They either batch it and send it email, or it’s sent out electronically through a data system.
“Through analysis of the data,” he said, “we’re able to tell them right away where they are stratigraphically, if the angle of the bit is keeping them consistent with dips of the formation they want to be in.
“We can tell them if they cross a fault, and because of the angle of the bit and the dip of the formation, we can tell if they’re trending toward drilling out of the top or bottom,” Gunn noted. “Knowing that, they can direct the engineer to reorient the bit or continue as is.”
For the uninitiated, AAPG member Jason Slayden, geology manager for the Permian Basin at XTO Energy, delved further into the basics.
His extensive experience with geosteering includes the Woodford shale with its extremely complex structural environment rife with faults and dip changes.
“The reason to use geosteering is, you’re drilling horizontally, so all the markers you’re looking for are stretched out, which makes them difficult to interpret or visualize,” Slayden said. “The geosteerers have software that lets them compress curves into a vertical type log and fit them back into a vertical correlation.
“It helps us by allowing us to visualize formation dip changes,” he said. “Even when you go across faults they’re able to match you up with where you faulted to, which can be especially difficult.
“In the Woodford, where you have faults that are smaller scale than the 3-D seismic can see, you’re not expecting these faults and they can pick them up fairly quickly,” Slayden noted.
“It’s a tool to visualize where we are in a vertical sense while drilling horizontally.”
Besides using this tool in various shales, XTO also has used it in coalbed methane plays and currently is applying it in some of their sand plays in the Permian Basin.
There is a relatively new trend for a company such as HSI to take on the entire geosteering process for a client. Given its lengthy history and a bevy of longtime experienced consultants on the roster, the company is often called on to do just that.
Slayden opted to take a different approach.
“My people and HSI both provide an analysis, but I want our guys to understand and think about where they are without relying on a geosteering company,” Slayden noted. “If they don’t stop to think where they are, the direction things are moving, they won’t know if the geosteering is right or wrong.
“The geosteering company provides us with a second set of eyes looking at the data,” he continued. “This provides us with a comfort level that’s very important and very valuable.
“It’s also a very cost-effective solution.”
Tackling Complex Geology
Chief Oil & Gas has had myriad occasions to apply the geosteering process in various plays.
They drilled several hundred horizontal wells in the Barnett shale play using HSI personnel, according to Steve Collins, geologist at Chief’s Carrollton-based office just outside of Dallas.
He noted that in some areas where they operate, the geology is “calm” so that landing the laterals and staying on target is pretty much a slam-dunk. This is not the case in the Marcellus shale, where Chief has been drilling for about six years.
“In some areas in Pennsylvania, the geology is very complex across some of our leases,” Collins noted. “There are very large thrust faults, so landing those laterals and keeping them on our centerline target can be challenging.
“The primary tool we use for geosteering in Pennsylvania is the LWD gamma ray log,” he said. “It’s great for steering there because you have obvious gamma ray signatures in the Marcellus that can be mapped for miles across counties.”
Collins noted they monitor the geosteering, but HSI assumes the principle responsibility for the steering.
“They’re part of our geo-team and are very valuable to us,” he said. “This frees up our geologists for other duties, so it’s very cost efficient, too.”
Pre-planning is key to successful geosteering, and Collins offered a concise summary of their approach:
“We acquire 3-D and interpret it, and the lateral is based on this,” he said. “We want to go around large thrust faults and areas with high bed dips, and the geophysicist(s) will interpret this along the lateral based on 3-D. This information goes to the geosteerer so he knows what to expect.
“When we start drilling, we use the LWD gamma ray, generally putting it in at kick-off point,” Collins continued. “That gamma ray data are periodically transferred to the HSI geosteerer who has the gamma ray data from a nearby pilot hole that drilled vertically through the entire Marcellus section.
“As he’s (steering) horizontally with the gamma ray readings, he’s interpreting stratigraphically where he is and (the driller) will make adjustments with the bit, going up or down to stay on centerline target.
“On reaching TD, we review the HSI interpretation of where the lateral has landed, what the bed dips were, whether any faults were cut. We take this interpretation and compare to what the geophysicist(s) indicated we would see based on 3-D.
“In the majority of cases, the two have compared very closely. We have a lot of confidence that we know exactly where the lateral has landed along section, where a fault may have been encountered. As we place the frac stages in the Marcellus, we know where to place them.
“The HSI interpretation also helps to determine where not to frac, such as where we cut a fault,” he said. “We’ll skip across the faulted interval.”