Lower Silurian Longmaxi formation (LSL) shale is widely and continuously distributed in the northeastern Sichuan Basin and, based on structural analogies with the gas producing LSL formation in the southeastern Sichuan Basin, has significant potential for shale gas exploration. However, limited research has been performed to evaluate the shale gas potential in this region. Samples from a recently completed exploratory well (Well-WQ2) in the northeastern Sichuan Basin indicate that the LSL shale has a vertical property sequence that closely resembles the vertical property sequences in wells in the gas-producing sections of the southeastern Sichuan Basin. The continuous sampling and analyses of Well-WQ2 have allowed a detailed investigation of the vertical variations in lithofacies, mineral characteristics, pore structures, and organic geochemical characteristics. The Longmaxi formation was divided into two third-order sequences (SQ1 and SQ2) based on systematic core observations and well logging analyses. Both SQ1 and SQ2 include a transgressive system tract (TST) and a high-stand system tract (HST). The lithofacies exhibit an upward decrease in the organic content. From SQ1 to SQ2, the quartz content, in situ graptolite content, total organic carbon (TOC) content, and brittleness index decrease, but the clay mineral content increases. The LSL shale sections from depths of 1204 to 1214 m and from 1271 to 1282 m possess well-developed fractures and high permeability. Additionally, the average porosity and permeability in SQ1 are higher than those in SQ2. In addition, the positive correlation between the TOC and quartz contents of the assayed samples suggests that much of the quartz is of biogenic origin. Changes in the sedimentary and diagenetic environments during deposition are two key factors that contribute to the observed vertical heterogeneity of the Longmaxi formation. In conclusion, the shale sections of the lower part of the SQ1, like their analogs in the southeastern Sichuan Basin, are the most favorable targets for shale gas production in the northeastern Sichuan Basin.

Due to their simplicity, empirical production forecasting methods have been used by the petroleum industry for decades. Since 2008, a number of empirical methods have been introduced to the petroleum industry, specifically for wells located in tight/shale reservoirs. However, most of these new methods are not reliable for forecasting remaining reserves, although they may appear to be very good for forecasting EUR in wells in which a high percentage of the EUR has already been produced. The Stretched Exponential Production Decline (SEPD) Method was introduced in 2010. Our results from analysis of both synthetic and actual field data by using SEPD have indicated that this method will most likely underestimate EUR in reservoirs with permeability ranging from 0.1mD to 0.0001mD. A modified SEPD (YM-SEPD) Method has therefore been developed to eliminate the SEPD Method's shortcoming by employing a new specialized plot to find all related parameters. This newly developed method is very easy to use and, most importantly, it will yield a much more reliable production and remaining reserve prediction for tight horizontal wells. With longer production histories, remaining reserves can be forecasted even more accurately and with a high confidence level. Hundreds of horizontal wells including oil wells from various formations (Cadomin, Montney, Notikewin, Cardium, Barnett Shale, Muskwa, etc.), hydraulically fractured in various ways, have been analyzed using the modified SEPD (YM-SEPD) method. Results indicate that reliable EURs and production profiles can be predicted readily for wells having only two to three years of production history. For wells having less than two years of production history, the modified SEPD (YM-SEPD) Method can also yield reasonable production forecasts when coupled with Duong's empirical method. This paper presents the application of the modified SEPD (YM-SEPD) Method to a number of actual and synthetic oil and gas wells to estimate their proved reserves, including horizontal wells producing dry, wet and retrograde gas as well as tight oil. These examples have had production histories with either observed or non-observed boundary-dominated flow (BDF). The examples also illustrate how the modified SEPD (YM-SEPD) method is capable of estimating proven reserves with high confidence.