This paper outlines a refrac pilot testing program conducted in the Eagle Ford Shale.As wells in the Eagle Ford accumulate production over time and the pressure around the horizontal wellbore declines, it is important to also consider communication due to offset fracture stimulation. Refracturing trials in older fields, such as the Barnett Shale have yielded a positive enhancement of well performance (Siebrits et al., 2000). This paper evaluates the concept of diverting fluid and proppant along horizontal wells in the Eagle Ford, while considering any communication with older producing wells during refracturing operations.Pumping data acquired during the refracturing is used to explain some of these concepts. Modeling of induced fracture geometry, considering the effect of current pore pressures, is conducted with a fully three-dimensional hydraulic fracture numerical simulator. The pressure of the subject zone may affect the containment and rate of growth of the new fractures, as well as the re-orientation of the existing fractures.Refracturing an old horizontal well with 5,000 ft lateral length and more than 800 existing perforation holes in the casing is very challenging and requires a careful integration of reservoir knowledge, completions skills and experience. The technical team at Pioneer Natural Resources has developed an integrated workflow to design and execute a refracturing job for an Eagle Ford well. The work flow includes: 1) identification of the lower pressure areas along the lateral using surveillance data from the well, such as microseismic, tracer logs, and production data. 2) identifying which wells within the drilling schedule are offsetting older wells that have high cumulative production, and 3) designing a single fracturing job with several sub-stages separated by diverting agents. Each sub-stage is intended to target specific areas along the lateral, which were previously identified as low pressure zones. Volumes and pump schedules will be specific for each candidate and are based on but not limited to proximity to an offset well, lateral length, and existence of geological structures such as faults and fractures in the area. The results from this pilot testing program such as the radioactive tracers and the fracture gradient changes before and after refrac will be evaluated upon completion of the field execution.
One of the most significant elements in the successful development of an unconventional multi-layered horizontal shale play, such as the Permian Basin Wolfcamp and Spraberry shales, is the continuous refinement of completion design programs in order to account for the specific geological characteristics of the target formation and spatial considerations. This paper examines a number of well completions, a large percentage of which are multi-stacked, over a four-year period in the Permian Basin. In this paper, we describe the ways in which a completion design program has been constantly refined in the development of Wolfcamp and Spraberry formations over certain areas of Midland Basin. Key performance drivers, such as regional pore pressure, rock properties and stresses, well spacing, etc. along with multidisciplinary data sets such as microseismic, tracers, bottom hole reservoir pressure, and production history are incorporated into modeling the completion designs. Details of the workflow, analysis of results and implementation of the Permian multi-stack design optimization plan are presented. The paper includes lessons learned from early vintages to modern completions, parent/child mitigation strategies, and future ideas to further optimize the operations. Information presented in this paper will help multi-disciplinary asset teams, consisting of engineers, geologists, analysts and managers; design a workflow for selecting appropriate design solutions for their individual shale assets.
Tight oil and shale gas resources produced 29% of total US crude oil and 40% of total US natural gas in 2012 (EIA). Technically recoverable quantities of shale gas and shale oil resources for the US are 665 trillion cubic feet and 58 billion barrels, respectively. Considering the impact of the "unconventional boom" on the economy, it is crucial to understand the production performance of wells to maximize the recovery from shale plays. The latest advances in Rate Transient Analysis (RTA) provide quick yet robust tools to assess the quality of the Stimulated Rock Volume (SRV) and long term performance of the wells by estimating EURs. The most common challenge in history-matching of production in shale gas/oil wells has been the non-uniqueness of the history-matched parameters. A lot of emphasis has been put on estimation of fracture half-length, which is believed to be a primary driver for the performance of shale gas/oil wells. Since linear flow is the main transient flow regime in the early life of a hydraulically-fractured shale gas/oil well, a Rate Normalized Pressure (RNP) versus Square Root of Time plot is the most commonly used diagnostic plot for the performance analysis of the wells. A*sqrt(k) or xf*sqrt(k) parameter groups are reported as a proxy for productivity in hydraulically fractured shale/gas oil wells. Besides having permeability as an unknown, the history-match is also sensitive to net hydraulic fracture height, which is one of the inputs to models that must be specified from other sources of information. This paper presents a novel approach for production performance analysis of shale gas/oil wells, which significantly reduces the non-uniqueness issues that one can have in comparison of performance. Twenty two Eagle Ford Shale wells were analyzed across the trend from lean gas to high-yield condensate to define a workflow that could be applied to other wells in different geologic areas, yet provide consistent comparison of long term performance (EURs).
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