LWD provides solution for bolstering shale gas economics

Just as success came incrementally to crack the code for making shale plays economically viable using advancing horizontal well drilling and hydraulic fracturing technologies, so too are the ongoing improvements for reducing drilling and completion costs and optimizing producibility.

Improvements in well steering along the lateral and downhole measurements, in particular, have been critical in optimizing well placement, an important key to economically maximizing production.

This model, with imported higher resolution log data and an azimuthal image with overlaid dips represented in green, was used to verify structure model and well placement. The green strike angle agrees and confirms the modeled formation dip. (Images courtesy of Schlumberger)

Work on Anadarko Petroleum Corp. operated wells in the active Eagle Ford shale play of South Texas has demonstrated the benefits of using real-time formation evaluation along the lateral to optimize well placement and improve drilling efficiencies, thus improving shale oil and gas economics.

It has been shown that LWD is a fast, cost-effective, and dependable method for conveying data for accurate and verifiable geosteering measurements, comprehensive borehole geology, shale gas petrophysical evaluation, stress assessment, and completion optimization. Integrating LWD into the bottomhole assembly (BHA) allows real-time formation evaluation that can assess rock properties in detail and thereforeexpedite accurate well placement. The subsequent LWD measurements in real time and pseudo-real time also can help avoid hazards, enhance ROP, and optimize completion design.

LWD measurements can help clarify issues with rock quality inconsistencies and variable well production results; the main goal is to gain insight into the reservoir-production relationship. Such knowledge enables operators to refine well placement objectives within the reservoir column and optimize the completion for the greatest estimated ultimate recovery (EUR) of reserves.

Improving shale gas recovery rates
While the industry has made tremendous gains in drilling efficiency in shale plays, the next big gains likely will be realized in production efficiency.

When these horizontal wells drift outside of their sweet spots, it is not unusual to see wells with recovery factors of perhaps one-third of their potential. A major concern is the effectiveness of a “one-size-fits-all” geometric well design approach in developing these resources that only emphasizes further gains in drilling efficiency.

A plan view of the wellbore trajectory shows microseismic events from hydraulic fracture monitoring. The red/blue curve on top indicates the fracture gradient displayed in dynamic range. Lower green/purple curve indicates brittleness. The circles indicate microseisms from different pumping stages. Microseismic data from the field clearly show that while the perforations were placed into the “brittle” high-stress interval, the fractures actually diverted into the nearby low-stress interval.

Recently, efforts to increase well recovery rates have focused on extending the lateral section and reducing stage lengths in a well. A study of more than 125 wells running production logs showed that almost one-third of the perforation clusters in a number of these shale plays provided a negligible amount of production. Comparing the production results of the average and exceptional producers, a 33% increase in contributing perforation clusters can increase initial gas production as well as EUR by up to 25%. Perhaps the most efficient way to increase the number of contributing perforation clusters is to incorporate key LWD measurements into the BHA while drilling.

Well placement key
Steering a well with a gamma ray-only measurement can lead to erroneous reservoir interpretations, inconsistent well production, and incorrect mapping of reservoir properties and reduced EURs.

Understanding and grouping physical properties of areas near the well bore optimizes the fracturing campaign and thus enhances production from all perforation clusters.

By employing proprietary geosteering software, it was possible to build a 3-D structure property model from the Eagle Ford pilot well’s logging data. The software was able to import a section from the model and use it to represent the formation dip and thickness, including faults and formation pinchouts. In this case the model was correlated with azimuthal images acquired during washdown. The modeled dip and formation thickness were adjusted so that the structure model agreed with logs and borehole images. This duplicated the process for real-time geosteering.

Of 15 drilled wells, those employing LWD for well placement produce 75% more than the 10 that were placed using non-azimuthal gamma ray. Only one of the wells placed with LWD produces below average.

This well was steered in real time using only an averaged, non-azimuthal gamma ray curve. Using this single measurement, the resulting interpretation concluded that the well had been placed in the middle of the reservoir and drilled into an interbedded lens along the lateral. The well was then dropped in angle to exit the lens. Employing post-drilling LWD measurements, a modeled interpretation was constructed. This model showed that the well had landed high in the reservoir and consequently exited the reservoir. The latter interpretation was verified by overlaying azimuthal images used to interpret dips. Using these images provided confidence in an alternative interpretation that was later reinforced by production results.

Optimizing drilling
LWD tools also can help optimize the drilling process, providing added sensors for detecting shock, monitoring annular pressures, and identifying sweet spots or hazards. In addition, LWD solutions can be cost-effectively employed to deliver real-time azimuthal data for formation evaluation in wells with high-angled trajectories.

Some have argued against LWD, citing costs of both the service itself and the potential risk of high lost-in-hole (LIH) cost. But in addition to improving ROP and the additional production outweighing the marginal added-service costs, LWD lowers drilling risk by allowing operators to monitor downhole drilling mechanics data that can identify borehole stability problems. It can be noted that no LIH events have been recorded in more than 50 shale gas wells employing advanced LWD techniques in laterals at the time of publication.

Additionally, real-time LWD azimuthal images can provide high-resolution structure mapping through improved depth matching of horizons. This assists in defining subsequent drilling targets in the play by improving the precision of the landing depth reference and thus enhancing an understanding of structure undulation and property variation.

Finally, the compressional, C-66 horizontal and C-55 vertical shears, and Stoneley measurements obtained from the LWD sonic tool enable direct calculation of the vertical and horizontal mechanical rock properties along the lateral. The computed outputs of elastic moduli, Poisson’s ratio, unconfined compressive strength, and minimum horizontal stress gradient are then used to enhance completion design via stage selection of similar stressed rocks, improved perforation cluster placement in the stages targeting the lowest stressed intervals, or by avoiding stage selection of non-productive intervals.

In addition to the Stoneley measurement’s use as a source for the C-55 vertical shear, it is also employed to identify and characterize borehole fractures via reflection analysis. Knowing whether fractures are open or healed is another critical input into completion design.

It is critically important to quantify the mechanical properties in these highly anisotropic environmentsbecause of all of the rock properties correlating to enhanced production; they are the most variable along the lateral. Microseismic data from the field clearly show that while the perforations were placed into the “brittle” high-stress interval, the fractures actually diverted into the nearby low-stress interval.

Unfortunately, without direct access via correctly placed perforations, near-well pinch-out in the high-stress rock will likely constrict the perforation channels, reducing or eliminating production in this stage. Total stage length and perforation cluster placement should be based on similar rock properties, similar stress, and hazard avoidance such as swelling clays.

Bottom-line results
LWD data also can be used to optimize frac stage design. The data are used to identify stress variability within each stage and across the well, avoid stimulating faults that can produce water or other hazards, target free gas, exploit fractures, and prevent swelling clays. These data assist in grouping like rock properties so perforations can be placed strategically to optimize production, avoiding faults while exploiting fractures.

A comparison of three-month production rates from similar wells placed at the beginning of field development shows significant improvement using LWD techniques. As always, there are some caveats. Exceptions to the assumptions presented can be the result of substantial variations in far-field formation properties that do not show up near the borehole. Thus, it becomes critical to further integrate post-production data with the entire field, including offsets, laterals, and the far field.

Increasingly, using LWD tools for real-time formation evaluation in horizontal shale gas wells is proving cost-effective, especially as industry moves away from the standard of using them not just to define a reservoir but to a new paradigm of full integration that includes completion design.

This article is based on paper SPE 139007-PP, “Unlocking the Secrets for Viable and Sustainable Shale Gas Development,” presented at the SPE Eastern Regional Meeting held in Morgan-town, W.Va., Oct. 12–14, 2010.