Operators in Argentina, Poland, China and Australia face the same types of challenges that North America has met over the past eight years in developing unconventional plays. No matter where a company operates, the need to understand the rock is paramount in opening oil and gas resources from nanodarcy formations.
“From a geological viewpoint, we’ve got to get as much rock data as we can. We have to get core data and openhole datasets on these exploratory and early appraisal wells and basically tear those data apart. What we then have to do is calibrate that core data to as much of the basinal data we have to create a petrophysical picture with a fairly limited dataset,” said Dick Stoneburner, managing director, Pine Brook Partners, at the DUG Australia conference in Brisbane, Australia, Aug. 27, 2014.
“What I have done is taken most of the successful American plays and broken them into what I call emerging, evolving and mature plays,” he explained. “I am trying to give you some sense of what we’ve been able to accomplish over the years. Prior to 2006, we really didn’t have a very good plan or technology to complete the rock effectively. When we were able to do isolated multistage hydraulic fracturing, we were then able to crack the code.”
As Stoneburner mentioned, there are geological, drilling and producing aspects associated with each of these maturity levels. “I challenge you early on to establish as much as you can about that core area,” he said. “Make sure you’re in the right rock to spend the capital necessary to test that particular play.”
Although an operator has to start out with a fairly conservative drilling approach in an emerging play, it would need to move away from that conservatism going from the emerging to the evolving play.
“Understanding the fluid types, proppant types and geometry in a new basin is very challenging. It takes a lot of time as well as trial and error, but we have to start working on that in emerging plays,” he continued.
The emerging plays he described were the Utica, Tuscaloosa Marine Shale, East Texas Eagle Ford and stacked plays in the Anadarko Basin.
About two-and-a-half years ago, the Utica was described as the next Eagle Ford. There was a very limited amount of data since there had not been any drilling in the area for decades. The challenge for those who decided to embark on an effort to lease within the Utica was: Where do you go?
“You had a pretty benign area from a data standpoint. You had a very benign area from an infrastructure standpoint. So it was very challenging to identify the areas you needed to go lease,” he added.
“I will tell you a lot of operators wanted to be in that core area. Unfortunately, most didn’t find the right area and [cumulatively] spent about $1 billion doing that,” he emphasized.
In the Tuscaloosa Marine Shale, operators have known for about 20 years there is oil there. However, the companies in the play earlier were not what Stoneburner would call experienced shale operators and had very poor results. Since then, three experienced main players have been involved, and results have improved, with 30-day IPs in the 800- to 900-bbl/d range.
“The problem is that about one in four wells has some sort of engineering failure. It is deep. It is hot. It is highly fractured. There are a lot of failures, particularly on the completion side,” he continued. “You have to be doing your engineering homework and some of the nondrilling data assessment prior to getting in there and understanding how you’re going to drill and complete those wells to avoid the pitfalls that a lot of these wells are currently experiencing.”
In the East Texas Eagle Ford, it took operators some time to get a good understanding of the physics involved. It is a matter of doing the petrophysical homework and understanding that what may not look great could be great if one does the right work to uncover it.
“Use different methods. One of these is the Passey method, which is basically using sonic and resistivity tools as opposed to conventional density neutron logs. A lot of these shales will more readily reveal themselves with this,” he said.
The stacked play in the Anadarko Basin was discovered by Newfield in the last 12 to 18 months. “What happened with Newfield is that they were drilling in the known Woodford play and encountered good shows and interesting rock. They did all their homework and defined a new play simply by understanding what the play was,” he continued.
There is no magical “tollgate” for moving from emerging to evolving plays. The more data a company has, the better geophysical model it can create.
“Early in a play you’re not going to spend money to acquire 300 or 400 sq miles [777 sq km or 1,036 sq km] of data before you have actually proven it is commercial. By this time you have proven it is commercial, and you do need 3-D data to avoid faults and other geologic hazards,” he noted.
“It is really important to understand the fluid types you’re using and that the geometry of that particular completion is appropriate to contact as much rock as you can—what is called stimulated rock volume.”
Operators will increase their capital exposure and move away from drilling a handful of wells to define the extent of the play. They now have to have multirig programs to be able to hold acreage. There is a very earnest effort to develop a play once it’s proven to be commercial.
“One thing I think is especially overlooked in a lot of wells is getting as much production log data as possible. You really don’t know how that wellbore is performing on a stage-by-stage basis unless you put something in the hole to measure it,” he continued. “You should use any kind of log that will give you an idea where production comes from. I encourage you to gather as much data as you can.”
Restricted-rate production is also important to maximize production. Stoneburner advised the use of it in the Haynesville, for example, where there is a lot of pressure-dependent permeability in the nanodarcy reservoirs.
“You can effect a lot of permeability early in the well life with your fracture stimulation. But if you lose that permeability by overproducing the well and allowing pressures to drop dramatically, you can effectively lose a lot of productivity. I would encourage you to study the effects of pressure-dependent permeability however you monitor that surface pressure,” he explained.
He listed the Niobrara Shale, Delaware and Permian basins as evolving plays, emphasizing, “Know your rock. Know your play.”
In the Delaware and Permian basins, understanding the burial history is key to finding the best resources. For example, the deepest part of the Delaware Basin is the least mature. “Your product type is a result of that burial history and is incredibly important, particularly in today’s world of depressed natural gas prices,” he said.
As operators move up the basin, they find that the maturity level increases at the western limits where gas is found. “The Davis Mountains tectonic event created the inverted basin. As it is today, even though there is good production in that area, it seems the most commercial area in this basin is in the gas-condensate window,” he continued.
In the Midland Basin, there was no depositional uplift. “In the central part of that basin, you have the thickest sediment, high pressure and corresponding best productivity. The center of the basin is where you want to be,” Stoneburner continued.
There are a large number of stacked reservoirs. The Wolfcamp is more than 305 m (1,000 ft) thick. With the Spraberry above it and the Pennsylvanian below it, as many as eight to 10 stacked reservoirs could be commercial.
The Niobrara extends across many intermountain basins in the central and western U.S. It is mainly in the Denver-Julesberg Basin, with rock also present in other basins like the Powder River and Wind River basins.
“The Niobrara is again a play where you better be in the core area. Know where the rocks are,” he emphasized.
Pad drilling in mature plays improves drilling efficiencies. Downspacing begins at this point.
“You are really trying to understand how many wells you need per section or how you are going to space this development. Quite honestly, I don’t think we have a very good handle on this in many plays at all. It is going to take quite awhile to really understand how these reservoirs are going to drain,” Stoneburner said.
He feels strongly about the concept of geometric vs. geologic completions. “Throughout my upstream career, virtually everywhere we wanted to stimulate every inch of that well bore. In a lot of cases all that wellbore wasn’t worth stimulating if you knew more about the rocks. I encourage you to get more openhole data on these laterals with quad combos or anything you can do to learn more about the wellbore itself and design your completions based on that geology as opposed to geometry.”
The Barnett, Haynesville, Fayetteville and Bakken he listed as mature plays. The Barnett was the first shale play in North America. But, he warned, it took George Mitchell and his team 20 years to understand the rock.
“One key lesson to learn from the Barnett is to look for the bottom seal for the shale formation. A lot of companies did not understand that a bottom seal was needed between the Barnett and the Ellenberger, which is a prolific water-producing reservoir in the area. I encourage you to not just focus on the rock, but focus on what is around you and what are frack barriers. How is that well going to frack relative to above and below the shale? It is very important to understand,” he added.
In looking at the Fayetteville, Stoneburner said it’s important to understand the structure. “Within that section there are an abundance of faults. You can actually see trendings southwest to northeast that are less productive or faulted areas that prove you can’t drill horizontally across these faults. When you are going sideways, it is really problematic if you don’t have a good idea of what you are going to run into,” he explained.
In opening the Haynesville, “It was an absolutely insane period in my life within the industry where we were paying upwards of $25,000 per acre to lease acreage. As it turned out, it was worthwhile. We did understand the sweet spot component of the Haynesville better than most. We felt like pressure, TOC [total organic carbon] and clay were our keys.
“When we found that in the north central Louisiana area we had all those components—the highest TOC and geopressure and the lowest clay percentage—that really defined the key to the reservoir,” he explained.
Avoid herd mentality
Stoneburner emphasized several times, “Understand what you are doing. Do not have the herd mentality and follow someone who says the Mississippi Lime is the way to go. ‘Chesapeake did it so I’m going to do it too.’ That happened a lot in this play, and a lot of people lost a lot of money.”
The Niobrara is another example of where the herd mentality kicked in, to the detriment of many operators. “Anywhere the Niobrara existed, people would go there. In this case, aside from the Wattenberg Field area that produces from the Niobrara, virtually no other areas in the entire central U.S. were commercial for the Niobrara,” he said.
Source: E&P Mag