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Li, Bingjian (Schlumberger Oil Field Services) | Chen, Yong-Hua (Southwestern Energy, Woodland, USA) | Gawankar, Kiran (Schlumberger-Doll Research) | Miller, Camron K. (Schlumberger Oil Field Services) | Xu, Weixin (Schlumberger Oil Field Services) | Laronga, Rob J. (Schlumberger Oil Field Services) | Omeragic, Dzevat (Southwestern Energy, Woodland, USA)
Abstract Distinguishing open natural fractures from healed fractures has been a significant challenge in shale formations drilled with oil-based mud. Ultrasonic imaging tools can locate open fractures, but such data is seldom acquired due to concerns related to the effects of heavy mud and, in high-angle wells, operational efficiency and tool eccentralization. Until now, the microelectrical image tools in the market were not capable of differentiating open fractures from healed fractures in oil-based mud. A new, high-definition oil-based mud microelectrical imager has been deployed that operates at high frequencies and provides images with high borehole coverage. This new tool can identify natural fractures, sub-seismic faults, and other geological features in the reservoirs. In addition to high-resolution images of formation resistivity, an advanced inversion processing can be applied to generate resolution-matched images of the quantified standoff between each sensor in the array and the borehole wall. Such standoff images are of special value for differentiating open fractures from healed fractures. The use of these standoff images are presented in several recent case studies from U.S. shale plays. In the first case study from a pilot shale well in the northeast, natural fractures are identified on the new microelectrical imager and then further interpreted as open, partially open or healed fractures based on the inverted standoff images. Such open fracture interpretation has been validated by ultrasonic image data from the same well. In the second case study from an Eagle Ford Shale lateral in south Texas, both natural fractures and sub-seismic faults were detected. Interestingly, one of the interpreted open faults based on standoff images was even evident on dynamic pressure data in a monitoring well nearby during the stimulation process. Natural fractures can impact the shale reservoir quality, completion quality, or both, depending on the fracture types and intensity. Therefore, it is beneficial to have a reliable dataset to sort fractures by their type: open, partially open and healed.
Stephenson, Ben (Shell Canada Energy) | Galan, Earl (Shell Canada Energy) | Fay, Mathew (Shell Canada Energy) | Savitski, Alexei (Shell International Exploration & Production Inc.) | Bai, Taixu (SEPCO)
Abstract The evidence for large-scale structural features (lineaments/faults) affecting a hydraulic stimulation is much more compelling than for small-scale features (natural fractures). Large-scale features are weaker and have similar dimensions to a typical hydraulic fracture. But is it beneficial to stimulate these features and what are the potential consequences? An analysis of structural features from the Marcellus and Duvernay formations has been undertaken, with static characterization (seismic, image logs and outcrops), dynamic characterization (fracture diagnostics and well performance) and geomechanical modeling; ultimately to understand whether, in the presence of structural features, any field development decisions might get impacted. Maps of structural features supported by seismic attributes are commonly challenged as to what they physically represent. Outcrop analogues demonstrate how strain is distributed in intrinsically layered media, such as shale. Therefore a shale may preferentially fold above a fault. Folding may result in strain partitioning, with bedding-parallel slip (shear) limiting the vertical extent and opening (dilation) of discrete fracture planes. Lineaments in Marcellus folds are either broad zones of axial kink-band deformation associated with higher bedding dips, or planar zones comprising reactivated natural fractures forming an inherited en echelon fabric. Lineaments in the Duvernay are zones of distributed deformation commonly associated with a subtle flexure above faults. A novel interpretation method of microseismic events in time reveals how lineaments are involved during a hydraulic fracture treatment driven by changes in net pressure. Hydraulic half-length is limited when fracs intersect a lineament at a high angle. This was confirmed by geomechanical modelling showing that lineament dilation prevents the opposite branch of the bi-wing frac from propagating. Diagnostics from plays with lineaments oriented close to maximum horizontal stress indicate that the length-scale of hydraulic communication is increased, because tensile reactivation is facilitated. Tracer data have been used to calibrate the conductive length-scale of these features in the sub-surface and also confirm that external fluids may be brought into the well-bore from underlying formations. Whether a lineament helps well productivity depends partly whether it is ‘contained’ or ‘uncontained’ within the over-pressured formation. In the uncontained case, stimulation efficiency and enhanced risk of external fluids needs careful monitoring. In the contained case, stimulation of a lineament may enhance productivity of a stand-alone well, but conversely this same lineament may exacerbate the Parent-Child impact once adjacent wells are drilled. A potential mitigation measure may be to modify the proppant or stimulation design to screen-out these high conductivity (or leak-off) pathways, rather than trying to stimulate them, thereby enhancing near-wellbore complexity. Paradoxically, the best way to handle large-scale structural lineaments may be to stimulate them in order to shut them off.
Abstract Unconventional completions in North America have seen a paradigm shift in volumes of proppant pumped since 2014. There is a clear noticeable trend in both oil prices and proppant volumes – thanks to low product and service costs that accompanied the oil price crash in early 2015. As the industry continues to recover, operators are reevaluating completion designs to understand if these proppant volumes are beyond what is optimal. This paper analyzes trends in completion sizes and types across all major unconventional oil and gas plays in the US since 2011 and tracks their impact on well productivity. Completion and production data since 2011 from more than 70,000 horizontal wells in seven major basins (Gulf Coast, Permian, Appalachian, Anadarko, Haynesville, Williston and Denver Julesburg basins) and 11 major oil/gas producing formations were analyzed to examine developments in proppant and fluid volumes. Average concentration of proppant per gallon of fluid pumped was used to understand transitional trends in fracturing fluid types with time. Production performance indicators such as First month, Best 3 or Best 12 months of oil and gas production were mapped against completion volumes to evaluate if there are added economic advantages to pumping larger designs. In general, all major basins have seen progressive improvements in average well performance since 2011, with the Permian Basin showing the highest improvement, increasing from an average first-six-months oil production of 25,000 bbl in 2011 to 75,000 bbl in 2017. The Gulf Coast basin, where the Eagle Ford formation is located, has seen a 6-fold increase in proppant volumes pumped per foot of lateral since 2011 while the Permian and Appalachian basins hit peak proppant volumes in 2015 and 2016 respectively. In Permian and Eagleford wells, higher proppant volumes in general have resulted in better production up to a certain concentration. In Williston and Denver basins, most operators are moving away from gelled fluids, and reduced average proppant concentration per fluid volume pumped shows inclination toward hybrid or slickwater designs. While some of these observations are tied to reservoir quality, proppant volumes have begun to peak as operators have either reached an optimal point or are in the process of reducing volumes. Demand for proppant is expected to nearly double by 2020. As oil prices continue to recover, well AFEs continue to increase, despite multiple efforts to improve capital efficiency. The need for enhanced fracture conductivity and extended half-lengths on EURs are been discussed by combining actual observed production data and sensitivities using calibrated production models. The industry is moving toward large-volume slickwater fracturing operations using smaller proppants, but he operating landscape is expected to see a correction when such designs become less economical.
The Middle Devonian Marcellus shale play has emerged as a major world-class hydrocarbon accumulation and represents one of the largest and most prolific shale plays in the world. According to many outcrop studies in the region, natural fractures are well developed in the Marcellus Shale. However, evaluating fractures in the subsurface is often a significant challenge due to a lack of sufficient data. Therefore, in the Marcellus Shale Energy and Environment Laboratory (MSEEL) consortium project, significant efforts have been made to acquire high-quality image logs in the Marcellus laterals. The project provided tremendous opportunities to characterize the natural fractures and sub-seismic faults and to evaluate their impact on well stimulation.
In this study, about 70,000 ft of acquired high-resolution logging while drilling (LWD) acoustic images from five long laterals located in Monongalia County, West Virginia, were processed and interpreted. In addition, the study used high-quality micro-resistivity images from a pilot well, allowing the evaluation of natural fractures in the entire Marcellus vertical sequence. Based on the available acoustic images, the natural fractures were classified into three basic categories: high-amplitude fractures, low-amplitude fractures, and faults. Further, larger open fractures can also be determined when a low-amplitude fracture is evident on caliper images. The fractures in the Marcellus usually have a medium to high angle dip; however, multiple fracture sets in terms of strike orientation were clearly observed in all the laterals. The fracture set with a strike at NE-SW (or 60-240 deg) seems to be the predominant one in all the wells. A few other sets, including those with N-S, NWW-SEE, and E-W strikes, were also observed. Several sub-seismic faults, with mostly a low dip angle and a NE-SW strike, have also been seen in two of the laterals. The fracture density is variable across all the laterals, ranging from very low (or none) to very high (up to 5 fractures per ft). The average fracture density for all the laterals is about 1 fracture per 10 ft. In the vertical sequence, the natural fracture development showed a clear preference for shale or shaly facies over carbonate-rich or thin limestone layers. The interpreted fracture and fault data were used as input data for the stimulation design with the purpose of better understanding the fractures' impact on well stimulation. Production data from the laterals were also used to evaluate the natural fractures’ influence on well performance. The quality image database and the consistent interpretation results for the entire project enabled a systematic approach to characterizing fractures and, more importantly, to evaluating the impact of fractures on well stimulation and production.
Abstract Does the sub-surface drive completion design or is the rock less of a concern with industry trends to higher proppant-, fluid- and stage-intensities? To address this challenge it was first necessary to understand; 1) how the sub-surface could potentially influence completion and stimulation design, 2) what are the available engineering levers and moreover, 3) whether well performance has actually been impacted by tailoring completions in different plays from specific case-studies. Although there is a multitude of published field examples of how completion design changes have driven value, clarity around the inter-connectedness with sub-surface variability, either between plays or within a play, is commonly missing. New templates have been developed that describe the conceptual links between the nine key 'Sub-surface Drivers' for hydraulic fracturing and their associated engineering Levers categorized by well-, fluid-, proppant- and stage-design. These templates are a compilation of extensive empirical observations from both operations and field performance reviews incorporating thousands of wells across North America, supported with learnings from geomechanical theory and modeling. The nine Sub-surface Drivers that influence completion design and control the access to hydrocarbons are, 1) mobility, 2) reservoir pressure, 3) gross thickness, 4) layering heterogeneity, 5) rock stiffness, 6) natural fractures, 7) stress anisotropy, 8) risk of fraccing faults and, 9) risk of fraccing out of zone. Drivers 1-7 govern the connectivity, whereas 8 and 9 influence stimulation ineffectiveness. It is proposed that there are approximately fifteen primary engineering Levers related to these nine Drivers, which have been shown to have a measurable impact on completion effectiveness and/or production. Case studies illustrate that the Sub-surface Drivers play a significant role in most plays, but they are not all relevant in every play. The challenge is to acknowledge the variability, or lack of, and pursue completion design optimization goals, while managing the variance in the well performance range. Whereas industry trends of increasing completions intensity have delivered more value in many plays, the Sub-surface Drivers concept have primarily proven useful to mitigate against poor wells in development and explain exploration failures. By developing a systematic set of templates for Drivers and their respective levers, learnings from other operators can be high-graded through the formulation of connectivity analogues with the goal of showing where changes in completion design may be more, or less applicable.