The natural gas production is gaining importance as a clean source of energy. Several potential sources exist for gas production in the Appalachian Basin with the Marcellus shale being the largest resource in the U.S. This covers several states in the Eastern U.S. and plays a vital role in the future of gas production. As a result operators are interested in the development of the shale resources mostly with multi-stage fractures using a horizontal well. However, the lack of commercially available information on well and treatment designs is rather vague. This information is critical in the determination of economics of gas production from shale wells. In this study, simulations have been conducted to determine the gas production from horizontal shale wells when limited data is used in the design of fracturing operations. Some of the parameters studied include horizontal and vertical stresses, the amount of fracture stages and formation properties along with others. The same treatment can yield different fracture geometry due to changes in formation properties; however, the gas production values after a single fracture treatment were similar for cases considered in this study.

Water is by far the largest waste stream associated with oil and gas production and it is unimaginable to find an oil reservoir absolutely free from connate water. Water management has become an important issue of hydrocarbon production, since the produced water increases as the field grows older and the cost of water handling, such as separation, treatment and repair is dramatically increasing. Down-Hole Separation (DOWS) and re-injection results in the production of oil to the surface, while portions of water are injected to the underground formation without ever being lifted to the surface DOWS depends on geological characteristics of the producing and injection formation, down-hole conditions, well configuration and equipment, installation procedures, hydrocyclone arrangement and water disposal. With their compact size, Liquid-Liquid Hydro-Cyclones (LLHC) can perform as an integral part of a down-hole oil water separation system. Despite performance and functionality of cyclones not being fully understood, they have created new possibilities for separating fluid down-hole for the producing formation and injecting separated water far away from the production interval. Before placing cyclones into practice, a study of fluid properties, well geometry, and characteristics of the formation can yield valuable information about the applicability and efficiency of DOWS. In this study, Computational Fluid Dynamic (CFD) was used to determine the effect of changes in API oil gravity, flow rates and cyclone geometry in order to understand the behaviour of LLHC in down-hole conditions. CFD is a tool that can predict the quantity of oil flow into surface, the quality of injected water into formation, split ratio, separation efficiency, mass transfer and related phenomena by solving numerically set of governing equations defining the fluid behavior in a DOWS.

Several techniques for hydraulically fracturing design were conducted in the liquid-rich Eagle Ford developments. This study shows that different results were observed due to the variation of geomechanical stresses of the rock across a play and reservoir properties. An optimum treatment for a liquids-rich objective is much different than that for a gas shale primarily due to the multiphase flow and higher viscosities encountered. This paper presents a treatment workflow that has been used with liquids-rich window of the Eagle Ford Shale. Review and integration of data from multiple sets across the play were used as input to a 3D hydraulic fracture simulator to model key fracture parameters which control production enhancement. These results were then used with production analysis and forecast, well optimization, and economic model to compare which treatment designs yield the best placement of proppant to deliver both high initial production and long term ultimate recoveries. A key focus for this workflow was to maximize proppant transport to achieve a continuous - optimum conductive - fracture half length. Often, due to the complexity of unconventional deposition, it is difficult to maintain complete connectivity of a proppant pack back to the wellbore. As a result, much of the potential of the fracture network is lost. Understanding the interaction of a hydraulic fracture and the rock fabric helps with the design of this behavior to achieve best results. These results can then be used for determining optimum well spacing to effectively develop a selected reservoir acreage. Currently, there are numerous wells and over two years of production history in much of the Eagle Ford. Comparison of these production results demonstrate the importance of employing a diligent workflow to integrate the sciences so that a proper understanding and application of hydraulic fracturing modeling can be achieved.

Many of the techniques for hydraulically fracturing design were attempted in the liquidrich Eagle Ford developments. This study shows why different results were observed due to the variation of geomechanical stresses of the rock across a play and related reservoir properties. An optimum treatment for a liquids-rich objective is much different than that for a gas shale due primarily to the multiphase flow and higher viscosities encountered. This study presents a new treatment workflow for liquids-rich window of Eagle Ford Shale. Review and integration of data from multiple sets across the play are used as input to a 3D hydraulic fracture simulator to model key fracture parameters which control production enhancement. These results are then used within a production analysis and forecast, well optimization, and economic model to compare treatment designs with the best placement of proppant to deliver both high initial production and long term ultimate recoveries.

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