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.

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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.

Shale gas exploitation has dominated the E&P landscape in North America for nearly a decade. There is a great deal of competition for shale acreage in the US, and leasing occurs rapidly once a new shale play is discovered. It can cover tens of thousands of acres and are often selected based on limited data, mainly vintage paper logs, mud logs, and access, cost, and availability considerations. Rarely are core, seismic or modern log data available to the operator. Capturing data in exploratory vertical wells is crucial, but comprehensive integration of the data to optimize horizontal well design is often overlooked. This paper discusses one operator's approach to fully integrate data captured in the Marcellus Shale in order to optimize horizontal well performance. Based upon insight from the study, the operator wanted to make more informed asset management decisions, improve economics, and look for future investment opportunities. Data were captured from vertical offset exploratory wells and an initial horizontal pilot well. The data that were acquired and incorporated into the study included field-wide seismic and data, as well as mineralogical, geomechanical, well plan, drilling, completion, microseismic, and production data from the aforementioned wells.A comprehensive study was performed incorporating the data to optimize the design of a horizontal well in the Marcellus Shale. This study was performed to get the operator up the learning curve in a short time period rather than by trial and error on wells. The first step in the study involved constructing a field-wide 3D static geologic model using the data captured above to determine the best petrophysical and structural areas to drill new wells. A reservoir model was then constructed with existing production, fracture, and microseismic data as well as the geologic model. The reservoir model was then used to forecast various production scenarios, including lateral length, number of stages, and perforation cluster spacing. Various fracture models were also included in the analysis to determine height growth and complexity.The results of these geologic, reservoir, and fracturing models were used to optimize the design of a second horizontal well drilled in the area of interest. The production increase between the first and second horizontal well was analyzed on a percentage basis. Lastly, recommendations were made for further well design enhancements based upon the study findings and the results of the second horizontal well.