Production data analysis and reservoir simulation of the Eagle Ford shale are very challenging due to the complex characteristics of the reservoir and the fluids. Eagle Ford reservoir complexity is expressed in the enormous vertical and horizontal petro-physical heterogeneity, stress-sensitive permeability, and existence of multi-scale natural fracture and fault systems. This complexity makes the prediction of the geometry and conductivity of the hydraulic fracture resulting from the stimulation process rather challenging. On the other hand, reservoir fluid complexity is demonstrated in multi-phase flow, liquid loading in the wellbore, condensate banking, etc. Based on this complexity, 3D reservoir modeling and numerical simulation have the relative advantage of addressing irregular fracture geometry, variable SRV, and multi-phase flow aspects. The South Texas Asset Team at Pioneer Natural Resources is establishing a workflow for dynamic reservoir modeling that can integrate all reservoir/wellbore parameters (formation evaluation, drilling, completion, stimulation, pre-/post-fracture surveillance, and well performance data) in order to address key questions relating to field development; such as depletion efficiency, drainage area, wells interference, and condensate banking effects. In this paper, a case study is presented to demonstrate the integration of various measurements and surveillance data to build a variable SRV reservoir model. The variable SRV model described here has the following building blocks: 1) Formation evaluation: included all the reservoir characterization data derived from logs and 3D seismic inversions and structural attributes. 2) Surveillance data integration: microseismic data (backbone for this work) are integrated with chemical and radioactive tracer logs. 3) Well performance data integration: Production data is used to determine different flow regimes during the well history and to set bounds for stimulation parameters, such as fracture half-length and permeability ( √ ). 4) Numerical simulation: Micro-seismic attributes (density and magnitude) are converted to a permeability model after being calibrated with tracer logs and production flow regime parameters ( √ ). PVT data is matched against an Equation of State (EOS) and input into the model. Production data history matching, sensitivity and forecasting indicate the following: a) The SRV created by fracture stimulation has permeability fading away from the wellbore; b) Fracture geometry is variable and results in an irregular drainage area along the lateral; C) Onset of condensate banking near wellbore and along the fracture(s) can occur within the first year of production if draw down is not managed properly.
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).
A US operator with a commitment to future drilling, stimulation and testing of unconventional wells has initiated a new evaluation to better define and understand the hydrocarbon plays along the northern margin of the Canning Basin’s Lennard Shelf and Fitzroy Trough. The goal of the evaluation is to determine the commercial viability of the region. In this paper, an integrated petrophysical hybrid model that has been calibrated to core data is highlighted. From this model, multiple play types were identified, including an unconventional siltstone-shale play, a conventional basin-centred tight gas play and a fractured tight gas play with potential analogs to North American unconventional plays. Six primary lithofacies were identified through the integration of thin section analyses, core descriptions, logs and petrophysical models. The results were calibrated to high-resolution formation image data to better understand the thin-bedded nature of these plays. The lithofacies were also utilised for defining core poro/perm transforms. Furthermore, an integrated descriptive mud log algorithm was utilised to define the types of hydrocarbons, including wetness, balance and ratios as the hydrocarbons’ fingerprints. Significant gas influxes were noted at the intervals with highly permeable beds, at swarms of fractures and faults, as well as within the organic rich layers. In this study, a pressure top seal for the Laurel Formation was defined as well as the highlights of one well, which includes 11 zones and over 389m of net pay behind pipe. The significance of this work is that it highlights a path forward for unconventional development that, if economically viable, would provide increased energy independence for Australia.
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