Lower risk lateral logging

When considering the downhole environment, one thing is certain. Every operator would like more data. When it comes to staying in zone and measuring and logging source rock in real time, logging-while-drilling and measurement-while-drilling (LWD/MWD) systems stand apart. While the value of these tools is apparent in today’s market, their high cost and the risks proposed in certain drilling environments make them limited in some areas. Namely, in North American shale plays, where horizontal laterals play a major role in the productivity of a well, logging has lost priority.

Because staged fracture completions have proven to be a viable means of producing from shales, very little data is needed. Traditionally, if logs can be performed on one or two wells, fracturing operations can be performed in a homogenous profile to develop an entire field. While this method of development has ensured success for operators in plays like the Fayetteville, Haynesville, and Eagle Ford, a new wave is entering the market: optimized completions.

Cost and risk
A major factor in proving shale development is to lower the per-well cost of drilling and completion. In shale development, horizontal laterals have shown to be the most effective form of bringing a well to production. Logging lateral sections using LWD/MWD, by recent standards, involves high cost and increased risk. LWD/MWD tools are set up as part of the bottomhole assembly of a drillstring. If the drillstring becomes stuck, or if there are any problems or tool failures, it could run costs into millions of dollars.

An operator beginning in a new area will often add the expense and science of logging its first few wells. The information garnered from this will be used on a number of new wells. The advantage of modern frac operations allows operators to complete a majority of wells with limited information on the actual well bore. As a result, many operators have removed data collection from their approvals for expenditure altogether for a number of drilling projects. By limiting logging operations for field development projects, operators are lowering cost and reducing risk. While this saves time and expense, it also greatly reduces the amount of information available on specific downhole environments and limits the ability to optimize completions.

This example from the Haynesville shows the drilling of the main part of the Haynesville and then drilling out of zone at the point the neutron (blue curve) separates further from the density (red curve). The gamma ray shows little difference, so the MWDGr would not be helpful in determining where to complete optimally. The TBL triple-combo shows in and out of zone, and thus, where to complete effectively. (Images courtesy of Thru-Bit)

Low-risk, high-quality data
First commercialized in January 2009, ThruBit’s through-the-bit logging (TBL) tool is a robust triple-combo (Gamma ray, resistivity, neutron and density/Pe [and neutron density]) that has proven to be a viable source of acquiring more data using an efficient, economical process that lowers risk by conveying through the drillstring and extending out the drill bit. The tool can acquire logs in a wide array of difficult scenarios because it can be deployed anywhere the bit can reach.

The tool is used in conjunction with a specially designed portal bit, which unlocks to allow the logging device to be run through the drillstring. Once the well bore has been circulated clean and the drillstring is “rabbited” to provide a minimum of 2½-in. drift, the logging system is run through the drillstring on wireline, staying connected to the logging unit. The tool is hung off above the bit, which enables the triple combo to be extended below the drill bit. With the wireline removed, the tool collects wellbore information in memory logging mode as the pipe is tripped at the surface.

For horizontal (or vertical) wells, the tools can be retrieved before the drillpipe is completely removed. This gives operators the ability to begin planning completion operations immediately. In addition, in the case of stuck pipe, the tools can easily be brought back to surface, allowing the driller to get rough with the pipe until it is unstuck. With the tools resting safely on the catwalk, there is no risk of incurring damage.

In addition to lowering risk for the operator, TBL also provides information that can be used to optimize well performance through the completion process. According to Bruce Noblett, petrophysical manager, ThruBit Logging Solutions, “The MWD gamma rays (MWDGr) that are run are good correlation tools. Because the standard deviation of a gamma ray tool is plus or minus a chart division, subtle yet important changes in reservoir quality can easily be overlooked.”

This example from the Eagle Ford shows zones of good porosity where the red and blue curve at right meet and cross. At the same time, the mudlog gas curve shows minor spikes of potential gas reservoir.

When an MWDGr is run in a horizontal lateral, it may read roughly the same in different intervals. With TBL’s higher sampling rate gamma ray (not an MWD) and all other triple combo data, “The whole story about porosity and the resistivity of the rock reservoir can be evaluated as it changes and completions will be optimized.”

Basic geology shows that most reservoirs do not remain homogenous. “Grain size changes, porosity changes, permeability changes, and fluids could change,” Noblett said. In some of the carbonate reservoirs, porosity sections vary from lateral to lateral. “So reservoir rock can change. And yet the gamma ray, if it has seen nothing but roughly the same type of lithology, looks similar but will stimulate differently.”

Gamma ray logs will show that a lateral stayed in zone, which often leads to completing the entire section. The possibility of seeing tremendous changes in the reservoir rock could cause major changes to the completions. Typically, the more porous sections are where the hydrocarbons will be stored. Higher porosities mean higher storage capacity. Using this information to optimize completions can prove better wellbore production. MWDGr is effective for many operations. Nevertheless, it can lead to blindly stimulating horizontal wells. With more information, operators can use subtle changes in rock structure to optimize the completion process.

This second example for the Eagle Ford shows similar zones of good porosity but more gas curve indication. The gamma ray reads similar in both zones. Interpreting this zone using only the MWDGr and gas curve would miss a reservoir of production throughout the previous Eagle Ford log. This is an example of needing all the information one can acquire.

Indication
Most companies want more data. To date, TBL’s triple-combo service has logged up to a 19,500-ft (5,944-m) well bore with 5,500 ft (1,676 m) of lateral — its deepest to date. By better understanding the layout of the zone of production, an operator can be better suited to further lower its costs and to improve production by optimizing its stimulation plan. Noblett reiterated, “Data is important; data helps make decisions; data also allows operators to realize the effectiveness of current projects and where things can be improved.”