Typical shale reservoirs in the US, such as the Haynesville, Eagle Ford, Marcellus, and Woodford shale systems, are being drilled and completed using horizontal well drilling technology and hydraulic stimulation methods. This exposes large surface areas of the source rock to highly permeable connectors that deliver hydrocarbons to the well bore.
As a result, the shale story has two parts: horizontal well construction and hydraulic stimulation that contacts the rock. Many practitioners in the field tend to treat the two parts as individual problems to be solved, but more and more people are beginning to realize that the two are intimately connected, and both can have a significant impact on production.
Current Practice
Typical geosteering practice in shale applications is to use a low-cost drilling and evaluation system for wellplacement. This usually consists of a mud motor, directional sensor, and gamma ray sensor. The objective is to place the well within a predefined section of stratigraphy by comparing the gamma log from the well being drilled to an offset or type log. Where markers correlate, the stratigraphic position of the well is known.
The quality of the correlation depends on many factors. A common issue is the signal-to-noise ratio of the sensor being used; a very noisy gamma log, for example, is very difficult to use for correlation. Borehole washout, along with mud properties, also can have a significant negative effect on the ability to correlate.
Another major issue in geosteering applications is what happens when a fault is crossed. Often, small faults are not detected on the gamma log, and it is not until a substantial portion of the well has been drilled outside the target zone that there is a realization that a fault has been encountered. A drawback of any correlation system is that the well must be traversing through the section, either up or down stratigraphically, to build a profile to correlate against the type log. This means that if the wrong decision is made about which way to correct after a fault, a much longer section could be drilled out of the target zone.
A recent internal study by Halliburton’s Sperry Drilling business line revealed approximately 50% of wells geosteered using the conventional gamma raygeosteering methods within an area of the Haynesville were misplaced for more than 50% of their lateral length. This was determined by using chemostratigraphic geochemical analysis, which is very effective at determining the stratigraphic position of a well bore. Even with a good gamma ray correlation, results often are ambiguous, and the position of the well in the formation is uncertain, leading to misplaced wells.
When looking at the complete system of well construction and stimulation, it must be determined whether placing the well within a specific piece of shale guarantees good production results. In other words, is there an agreement between final production results and gamma ray stratigraphy? Many operators do not believe there is. Even operators that are getting good results now are asking what more can be done on the well-construction side to improve productivity, pushing down the ultimate cost per unit production.
Future Possibilities
Basic criteria for producing hydrocarbons from shales are total organic carbon (TOC) content, thermal maturity, and the stimulation potential of the rock. From a well-placement perspective, it is possible to steer according to TOC, but this usually is well-distributed in the shale in which a horizontal well is placed. Thermal maturity usually is a function of the play and is determined well ahead of horizontal drilling. Neither of these properties is significant in terms of where the well is placed within a target interval. A typical target can be 30 ft (9 m) thick and have ample TOC in the sequence and the desired thermal maturity. This leaves stimulation potential as the desired property affecting well placement.
A lot of work has been done from the stimulation side on examining rocks for stimulation potential. Brittleness, derived from the ratio between Young’s modulus and Poission’s ratio of the rock, is one property that is recognized as being significant to stimulation potential. The amount of layering around the well bore also can be a significant factor affecting the ability to stimulatethe rock. Natural fracture systems play a part in some reservoir systems as well.
The key to unlocking the potential of these plays is to determine which particular property has the most significant impact on the ability to stimulate for better production. Once this property has been identified, the necessary tools can be deployed to measure the property not only after the well has been drilled and before stimulation but also in real time to assist in well placement. Deriving real-time brittleness and layering from sonic LWD measurements and making steering decisions based on that data could be the game-changer for operators struggling to realize the full potential of their assets.
The value of using a simple targeted suite, such as a gamma/sonic suite, is realized not only through better well placement in more suitable rock for stimulation but also in bridging the gap from well construction to stimulation. Deciding where and how to run multiple stages in a number of stages becomes a question of good practice based on hard data rather than a scattergun approach based on the notion that any frac is a good frac. While many operators now are leaning toward a stimulation model with many closely spaced stimulation points, using hard data to ensure optimal placement of the stimulation points has not yet become common practice.
As shale plays continue to evolve, the value of better well placement will become more apparent, with focused measurement systems that not only better position the well for stimulation but also allow for better stimulation placement and design. Such an approach can lead to better returns on capital spending in the form of more production of hydrocarbons per dollar, which is the ultimate metric for operators.
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