Production from shale gas reservoirs has formed an increasingly large part of the U.S. natural gas mix in the last few years. More than half of the rigs in onshore U.S. will be drilling horizontal wells with a large majority in shale plays 1. Within the last year, shale gas plays have dominated the onshore U.S. natural gas drilling activity, with this boom occurring during a time of economic uncertainty. However, skepticism has recently been placed on shale gas production decline trends from consultants and investment firms, where estimated ultimate recoveries (EURs) and the overall economic feasibility of shale gas plays have been brought into question. EURs of shale gas wells have been forecast in a number of ways within the industry. Some entities have been calculating EURs based on initial production rates (IPs). Others are applying the decline trends established in one basin to a different newer basin with less production history. In other cases, two different operators may use different trend types in wells that are in the same location. This paper seeks to more accurately assess the decline trends and EURs of these shale plays, if the decline trends are improving, and what returns are required to make a well economically feasible. This study compares the production trends of horizontal wells in the Barnett, Fayetteville, Woodford, Haynesville and Eagle Ford shale plays, analyzing each over time to determine if there have been improvements to production. Where applicable we address the impact that technology has made in this enhanced production. Furthermore, the decline trends of horizontal shale to horizontal tight gas sandstone plays are examined to look for differences and shed some light on potential EURs. The results of the analysis helped establish which decline trends could be used to determine the EUR of these horizontal shale wells, or if a better methodology may exist. A basic economic analysis to estimate breakeven gas price for an average (P50) horizontal well in each play was performed.
Multi-stage stimulation has become the norm for unconventional reservoir development. How many fracture treatment stages and perforation clusters are optimal? What is the ideal spacing between perforation clusters? Where is the best location for each fracture treatment stage? These are critical and difficult questions to answer when designing completions for tight gas and shale reservoirs and the approach to answering these questions can differ considerably for vertical and horizontal wells in different lithologies. In the past, optimizing the number and location of fracture treatment stages has been primarily a manual, time intensive process, resulting in a "cookie cutter" approach that may not properly account for vertical and lateral heterogeneity. This paper details new algorithms and an integrated workflow that could improve fracture treatment staging in both vertical and horizontal wells. The primary obstacles to optimizing completions in tight gas and shale reservoirs have been the absence of hydraulic fracture models that properly simulate complex fracture propagation which is common in many reservoirs, efficient methods to create discrete reservoir simulation grids to rigorously model the hydrocarbon production from complex hydraulic fractures, automated fracture treatment staging algorithms, and the ability to efficiently integrate microseismic mapping measurements with geological and geophysical data. One of these obstacles has been overcome with the recent development of complex hydraulic fracture models (Meyer and Bazan, 2011, Weng et al., 2011, Xu et al., 2010). However, the remaining obstacles are just now being addressed. Algorithms for efficient and rigorous design of multi-stage completions are detailed in the paper. Separate staging algorithms have been developed for vertical and horizontal wells that utilize detailed stress, rock mechanical, and image measurements (i.e. - natural fracture identification) to select stage intervals and perforation locations. The staging algorithms incorporate "fit-for-purpose" hydraulic fracture models ranging from standard planar pseudo 3D models to newly developed complex fracture models, depending on the environment. The algorithms are seamlessly integrated with microseismic measurements, a common Earth Model, and automated routines to discretely grid the complex fracture geometry for reservoir simulation. A common software platform enables the efficient utilization of multiple data sources from multiple disciplines. The application of the newly developed algorithms and integrated workflow is illustrated using examples from tight gas and shale reservoirs.
The US Energy Information Administration's forecast gas price is below USD 5/Mcf through
Across many shale plays in North America, operators ask why production performance disparities exist among horizontal wells. For example, even though drilling and completion practices of a neighboring operator may be mimicked, significantly different production results are frequently observed. Several hypotheses have been presented on the subject with little consensus. In most of these wells, formation evaluation in the lateral section is limited to gamma ray. Using a single curve to model the structure leads to multiple solutions with no way to determine which one is correct. Accordingly, large uncertainties may exist in: 1) determining the relative geologic position of the wellbore, 2) placing perforation clusters, and 3) selecting the appropriate staging design and stimulation treatment for the resulting well placement.To produce wells that perform to their maximum potential, it is fundamentally necessary to understand both the placement of the lateral in the reservoir and the placement of the perforations in the lateral. To optimize these placements, some measurements must be taken in the lateral. Obviously, the value of understanding where to locate the lateral and the perforations must be greater than both the direct costs associated with taking these measurements and the risk weighted costs associated with deploying tools in the lateral. A way to acquire this information while mitigating many of the aforementioned concerns is logging while drilling (LWD). Some of the measurements that LWD can capture along shale laterals include borehole/azimuthal images, stress, and mineralogy. With these comprehensive LWD measurements, not only can the captured data be taken for future completion design and analysis, they can also be used while drilling the lateral to steer the wellbore towards a desired target more accurately than gamma ray only. This paper focuses on how lateral LWD measurements impact well placement, perforation selection, hydraulic fracture stage spacing, completion design, resultant production, and subsequent economics of horizontal shale wells. Practical LWD examples from the Eagle Ford and Woodford Shale plays are presented, along with their impact on the aforementioned subjects.In this paper principles of using LWD measurements and interpretation in a field development plan are described, including relating LWD data to additional functions such as completion design, microseismic hydraulic fracture monitoring, production monitoring, and production logging. Ideas on how to optimize the amount and type of LWD measurements are proposed. Lastly, the paper will examine the impact of LWD measurements on the overall economics of horizontal shale wells.
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