A Barnett shale water-production data set from approximately 11,000 completions was analyzed using conventional statistical techniques. Additionally, a water/hydrocarbon ratio and first-derivative diagnostic-plot technique developed elsewhere for conventional reservoirs was extended to analyze Barnett shale water-production mechanisms. To determine hidden structure in well and production data, self-organizing maps and the k-means algorithm were used to identify clusters in data. A competitive-learning-based network was used to predict the potential for continuous water production from a new well, and a feed-forward neural network was used to predict average water production for wells drilled in Denton and Parker Counties, Texas, of the Barnett shale.Using conventional techniques, we concluded that for wells of the same completion type, location is more important than time of completion or hydraulic-fracturing strategy. Liquid loading has potential to affect vertical more than horizontal wells. Different features were observed in the spreadsheet diagnostic plots for wells in the Barnett shale, and we made a subjective interpretation of these features. We find that 15% of the horizontal and vertical wells drilled in Denton County have a load-water-recovery factor greater than unity. Also, 15 and 35% of the horizontal and vertical wells drilled, respectively, in Parker County have a load-recovery factor greater than unity.The use of both self-organizing maps and the k-means algorithm showed that the data set is divided into two main clusters. The physical properties of these clusters are unknown but interpreted to represent wells with high water throughput and those with low water throughput. Expected misclassification error for the competitive-learning-based tool was approximately 10% for a data set containing both vertical and horizontal wells. The average prediction error for the neural-network tool varied between 10 and 26%, depending on well type and location.Results from this work can be used to mitigate risk of water problems in new Barnett shale wells and predict water issues in other shale plays. Engineers are provided a tool to predict potential for water production in new wells. The method used to develop this tool can be used to solve similar challenges in new and existing shale plays. IntroductionLarge bodies of data relating to fracturing operations in gas shales exist in public databases. These databases also contain production data. In this work, we first examine production figures from the Barnett shale using conventional statistical techniques to identify trends and extract meaningful information from these trends.Second, some work has been conducted on characterizing water-production mechanisms in conventional hydrocarbon reservoirs on the basis of the analysis of water/oil-ratio (WOR) and water/gas-ratio (WGR) data over time (Chan 1995). This technique has not been applied yet to understanding the water-production mechanisms in unconventional gas reservoirs. Therefore, we
The flow behavior in nano-darcy shales neighbored by high conductivity induced natural fractures violates the assumptions behind Arps' decline models that have been successfully used in conventional reservoirs for decades. Current decline curve analysis models such as Logistic Growth Analyses, Power Law Exponential and Duong's model attempt to overcome the limitations of Arps' model. This study compares the capability of these models to match the past production of hundred shale oil wells from the Eagle Ford and investigate how the choice of residual function affects the estimate of model parameters and subsequently the well life, pressure depletion and ultimate recovery. Using the proposed residual functions increased the tendency of deterministic models to have bounded estimates of reserves. Results regarding well performance, EUR, drainage area and pressure depletion are obtained quickly and show realistic distributions supported by production hindcasts and commercial reservoir simulators. Overall, the PLE and Arps' hyperbolic models predicted the lowest/pessimistic and highest/optimistic remaining life/reserves respectively. The newly proposed residual functions were thereafter used with the Arps' hyperbolic and LGA models. We found that the use of rate-time residual functions increased the likelihood of the value of hyperbolic exponent being less than 1 by 87.5%. The proposed residual functions can be used to provide optimistic and conservative estimations of remaining reserves and remaining life using any of the above decline models for economic analysis. The key results provided by the modified DCA models help in long-term planning of operations necessary for optimal well completions and field development, accomplished in a fraction of the time currently required by other complex software and workflows.
A three dimensional geomechanical model was built using commercially available Finite Element Analysis (FEA) software to simulate propagating hydraulic fracture (HF) and its interaction with a vertical natural fracture (NF) in tight medium. The approach initially involved studying simple three dimensional single layered model followed by complex three layered model. The main area of concern was the fluid continuity at the HF-NF intersection. Different approaches were considered to model this fluid continuity. Finally, newly introduced elements were used for modeling the intersection of the NF-HF planes. These elements have ability to model the fluid continuity at HF-NF intersection. It was observed that for high stress contrast the NF activated length is smaller compared with the low stress contrast. For high stress contrast with principal horizontal stresses reversed, the HF intersects, activates and opens the NF. Increasing the injection rate results in longer and wider HF but does not significantly affect the NF activated length. Injection fluid viscosity shows an inverse relationship with HF length and a proportional relationship with HF opening or width as well as with NF length. It was observed that a weak NF plane temporarily restricts the HF propagation. On the other hand, a tougher NF or a NF with properties similar to surroundings does not show this type of restriction. The NF activated length was found maximum in the case of weaker NF and nearly zero in the case of stronger NF and NF similar to surroundings. This paper presents the results for a three layered, three dimensional geomechanical model with single HF and NF orthogonally intersecting each other, using the newly introduced cohesive elements for the first time in technical literature. Further a detailed sensitivity analysis considering the effect of stress contrast, injection rate, injection fluid viscosity and NF properties on this HF-NF interaction was conducted.
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