The Heterogeneity Index (HI) process was utilized in order to demonstrate production gain opportunities in a very short period of time, in a large mature ME field with around 500 wells producing from different reservoirs. The HI process provided a quick screening method of identifying preliminary candidate wells with anomalous behavior (over/under performance) for further analysis and most importantly, provided the foundation for the overall Structure Production Approach. This process; HI, can be calculated by utilizing OFM. A Cross Hair Plot has also been utilized to show the comparison of the HI of two variables in the same plot, creating an easy way to identify wells behaving differently from the average. The cross hair plot can be combined with X-Y Coordinated plot which reproduces the location of the wells. The results from this screening tool were utilized to identify the families of productivity problems at field level, and additional fast screening was done at well level to identify candidates for production enhancement. Representative Wells were selected for detailed diagnostics based on the relevance and size of productivity impact and, the potential of its production rate or well deliverability. Once a few "top potential" wells were identified, production engineering workflows were implemented in order to assess and forecast the potential of production incremental and try to determine and evaluate the best probable action. Some of the key innovate workflows used to complement production enhancement were: Time- lapse nodal analysis (honoring production history and neighboring wells), rate transient analysis (to consume sporadic/low frequency production data), single wellbore modeling (based on logs and flow units), among others. This paper will demonstrate the Production Enhancement Technologies Methodology, in particular the HI process with real examples; pending on data release approval from the owner and the progress of the operations.
Often and for many reasons the wellbore does not completely penetrate the entire formation, yielding a unique early-time pressure behaviour. Some of the main reasons for partial penetration, in both fractured and unfractured formations, are to prevent or delay the intrusion of unwanted fluids into the wellbore, i.e., water coning. The transient flow behaviour in these types of completions is different and more complex compared to that of a fully penetrating well. This paper proposes a method for identifying, on the pressure and pressure derivative curves, the unique characteristics of the different flow regimes resulting from these types of completions and to obtain various reservoir parameters, such as vertical and horizontal permeability, fracture properties and various skin factors. Both naturally fractured and unfractured (homogeneous) reservoirs have been investigated. For a naturally fractured formation, the type curves of the pressure and pressure derivative reveal that the combination of partial penetration and dual-porosity effects yields unique finger prints at early and transition periods. These unique characteristics are used to calculate several reservoir parameters, including the storage capacity ratio, interporosity flow coefficient, permeability and pseudoskin. Equations have been developed for calculating the skin for three partial completion cases: top, centre and bottom. The analytical solution was obtained by combining the partially penetrating well model in a homogeneous reservoir with the pseudo-steady model for a naturally fractured reservoir (NFR). The interpretation of pressure tests is performed using the TDS (Tiab's Direct Synthesis) technique for analyzing log-log pressure and pressure derivative plots. The TDS technique uses analytical equations to determine reservoir and well characteristics without using type-curve matching. These characteristics are obtained from unique fingerprints, such as flow regime lines and points of intersection of these lines, which are found on the log-log plot of pressure and pressure derivative. Two numerical examples are included to illustrate the application of the. proposed technique. Introduction Consider a vertical well partially penetrating a naturally fractured reservoir, i.e., only a portion of hydrocarbon-bearing formations is perforated. The naturally fractured reservoir has an infinite radial extent. The Warren and Root(1) model is used in which the matrix blocks are replaced by a system of uniform rectangular parallelepipeds with identical properties. The fractures are assumed to be parallel with the principal axes. FIGURE 1: Different types of partially penetrating vertical wells based on the position in the perforated interval hw. Available in Full Paper The pressure solution is derived using the Laplace transformation and the separation of variables technique as proposed by Bui et al.(2). This solution is expressed as an infinite Fourier-Bessel series in Laplace domain. The theory for a partially penetrating well in a homogenous reservoir developed by Yildiz and Bassiouni(3) is used for comparison purposes. The analytical solution for constant flow rate in Laplace space was inverted into real dimensionless pressure using the Stehfest algorithm(4). Pressure Derivative Behaviour Four types of partial penetration or completion schemes are considered (as shown in Figure 1). A plot of the dimensionless pressure derivative tD * P'D versus tD is shown in Figures 2 and 3.
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