A non-fractured horizontal well is often not economically attractive in reservoirs where vertical wells are fractured. In many areas the latter are less expensive to complete and, with proper design, they provide at least as good and, usually, better well performance than horizontal wells. A considerable problem with horizontal wells is that they are rarely properly completed and/or stimulated. One way, for a horizontal well to be potentially more attractive than a fractured vertical well, is for itself to be hydraulically fractured. For almost all petroleum engineering applications, at depths where producing formations are found, the stress field leads to a hydraulic fracture that is vertical and normal to the minimum horizontal stress. Therefore the fracture direction and azimuth become important considerations in fracturing horizontal wells and they affect the well orientation. There are two limiting cases: the longitudinal and the transverse. For transverse fractures intersecting a horizontal well it is possible to generate multiple fractures with proper zone isolation. The flow configuration in a transverse fracture intersecting a horizontal well generates an additional pressure drop which can be substantial. We provide a calculation procedure for this and relate the performance of each fracture with well-established methodologies, such as the dimensionless productivity index. Obviously, one transverse fracture intersecting a horizontal well cannot deliver the same performance as a fractured vertical well. Multiple transverse fractures are essential to make this configuration attractive. Thus, the question that we answer and quantify is the impact of multiple transverse fractures compared with the base case of a fractured vertical well. What differentiate oil from gas reservoirs are the turbulence effects, often dominating the performance of a gas well but usually negligible in oil wells. This difference leads to a distinguishing performance between oil and gas wells. We present a comparative study of transverse fractures intersecting a horizontal well in oil and then in gas reservoirs, showing their significant differences. Introduction Since the inception of fracturing of horizontal wells in the late 1980's, several field cases have been reported in the literature. In the Lost Hills Diatomite in California, a greatly improved production response was reported in horizontal wells after they were hydraulically fractured [1].In the upper Behariyia reservoir in Egypt, a thin and low permeability layer, fractured horizontal wells were completed with success [2]. The application of fractured horizontal wells in gas production was also reported in Australia [3]. Because the fracture orientation is not affected by human actions there are two obvious limiting cases:the well is drilled along the expected fracture trajectory; this is the longitudinal configuration.The well is drilled normal to the expected fracture trajectory. In this case a transverse hydraulic fracture can be generated [3, 4, 5]. A longitudinally fractured horizontal well has been shown to be attractive in relatively higher-permeability reservoirs [6, 7]. However, operationally, the required well azimuth may be quite difficult to drill and to be maintained in a stable condition to be subsequently fractured. In the McLure shale of the Rose Field in Central California[8], a longitudinal fracture was intended to be generated along the lateral length of horizontal wells. But the actual fracturing proved complex with 45% of the intended longitudinal fractures being transverse and 35% of the intended transverse fractures being longitudinal with the remainder ending up as horizontal fractures. Although the original goal of creating longitudinal fractures was not achieved, transverse fractures proved better than longitudinal fractures in production.

With the increased demand for energy and the declining conventional hydrocarbons worldwide, energy companies are turning to unconventional resources such as shale gas. With more than 2,000 Tcf of gas in place indentified in just 5 shale gas plays in the United States, shale-gas formations are now the number one targets for exploration drilling. Furthermore, there are still many more major shale-gas plays and basins waiting to be explored, evaluated, and developed. Because of the extremely low permeability of most shale formations, it is essential to select the appropriate completion techniques for shale-gas reservoirs. There are very few papers in the petroleum literature that provide a logical method to select completion techniques for given shale-gas-reservoir conditions. There are papers discussing successful completion techniques that seem to work for a specific shale. We have used many of these SPE papers to help define "best practices" in completing shale-gas reservoirs. We then developed logic to determine the best practice in completing shale-gas reservoirs as a function of reservoir conditions. In this paper, we will specifically cover the logic we have developed for choosing completion techniques in shale-gas reservoirs.First, we performed a literature review on the five basins as well as on all shale-gas plays in the US to determine the best practices in shale-gas completion techniques in fluctuating price environments and identify key geologic parameters that affect overall well performance. From our literature review, we identified seven pertinent geologic parameters that influence shale-gas completion practices. Next, we identified different completion trends in the industry for different geologic settings. Subsequently, we generated an economic model and performed sensitivity analysis to determine optimal completions for each gas-shale basin. On the basis of these economic models, we developed decision flow charts to select completion techniques. Finally, we programmed the flow chart, and we call this program Shale Gas Advisor. This program can be used to determine optimum completion best practices not only for the five gas-shale basins discussed, but also for gas-shale plays that have similar geologic attributes. We validated the program with published case histories in the SPE literature.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractA non-fractured horizontal well is often not economically attractive in reservoirs where vertical wells are fractured. In many areas the latter are less expensive to complete and, with proper design, they provide at least as good and, usually, better well performance than horizontal wells. A considerable problem with horizontal wells is that they are rarely properly completed and/or stimulated.One way, for a horizontal well to be potentially more attractive than a fractured vertical well, is for itself to be hydraulically fractured.For almost all petroleum engineering applications, at depths where producing formations are found, the stress field leads to a hydraulic fracture that is vertical and normal to the minimum horizontal stress. Therefore the fracture direction and azimuth become important considerations in fracturing horizontal wells and they affect the well orientation. There are two limiting cases: the longitudinal and the transverse. For transverse fractures intersecting a horizontal well it is possible to generate multiple fractures with proper zone isolation.The flow configuration in a transverse fracture intersecting a horizontal well generates an additional pressure drop which can be substantial. We provide a calculation procedure for this and relate the performance of each fracture with wellestablished methodologies, such as the dimensionless productivity index. Obviously, one transverse fracture intersecting a horizontal well cannot deliver the same performance as a fractured vertical well. Multiple transverse fractures are essential to make this configuration attractive. Thus, the question that we answer and quantify is the impact of multiple transverse fractures compared with the base case of a fractured vertical well.What differentiate oil from gas reservoirs are the turbulence effects, often dominating the performance of a gas well but usually negligible in oil wells. This difference leads to a distinguishing performance between oil and gas wells. We present a comparative study of transverse fractures intersecting a horizontal well in oil and then in gas reservoirs, showing their significant differences. c DV DTH s J J + = ) 1 (

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As compared to a well in a conventional gas reservoir, a well in a tight gas sand (TGS) reservoir will have a lower productivity index and a small drainage area. The economic risk involved in developing a TGS reservoir is much higher than the development of a conventional gas reservoir as the economics of developing most tight gas reservoirs borders on the margin of profitability. Therefore, it is important to select the appropriate drilling method and technology to drill a given TGS reservoir condition. In our review of the petroleum literature, we have found few papers that provide a logical method for selecting the best drilling method and technology for a given set of reservoir conditions. There are individual papers that discuss individual, successful field cases where specific drilling methods and technology seem to work for specific reservoirs. We have used many of these SPE papers to help define "best-practices" concerning the selection of drilling technologies and methods. We then developed logic to provide advice on the best drilling technologies and methods for specific reservoir conditions. In this paper, we will explain the logic we have developed for choosing drilling technologies and methods for drilling a TGS reservoir. For several years, we have been working on software we call TGS Advisor. TGS Advisor can be used to provide advice to engineers developing TGS reservoirs. The program can be described as an ‘Advisory System’. The user enters the known reservoir data and the program provides advice on how to drill, complete and stimulate the reservoir. We have combined knowledge from the petroleum literature and interviews with experts to build the TGS Advisory system. We evaluated the results of the advisory system with published case histories in the SPE literature. In this paper, we will describe how we have included the selection of appropriate drilling technologies and methods used to develop TGS Reservoirs.