Evaluation of Frac and Pack Completions and Future Outlook

Abstract

Abstract Frac and Pack introduced in the early 90's in the Gulf of Mexico has become a well established completion procedure aimed at enhancing the productivity of gravel packed wells. The technique consists of incorporating a "tip screenout 1" hydraulic fracturing treatment as part of the gravel packing procedure, thus stimulating the well. However, published well test data, although showing generally better productivity than classic gravel packs, presents positive skin values indicating near wellbore damage and often questioning the existence of a fracture intersecting the wellbore. This paper quickly reviews published data and outlines a methodology which integrates the analyses of the fracture placement data and the well test data. This integration results in a more realistic modeling of the system well and reservoir and characterizes the hydraulic fracture intersecting the wellbore. It is shown that poor fracture conductivity and / or high fracture face skin damage coupled with wellbore storage can reproduce the behavior observed in well test data and commonly interpreted with a non fractured model. The effects of additional pressure losses across the gravel pack can also be incorporated for a more realistic modeling. Field examples are discussed to illustrate the technique and a quick outlook of how completions of unconsolidated sandstones may evolve is presented. Introduction The number of Frac and Pack treatments has been steadily increasing since the early nineties following the initial publications2–7 which appeared in 92–93. Several hundreds are now performed every year. The main driver is enhanced economics due to the improvement of well productivity through a better reservoir - wellbore connection. This is provided by a tip screenout hydraulic fracture treatment performed in conjunction with the gravel pack placement. Published results4–9 confirm the productivity increases and explain the continued popularity of the technology. However, well test data interpretation often indicate damaged wellbores with positive skin values5–10, while frac and pack placement data generally indicates achievement of tip screenout and creation of a fracture2,9,10. In this paper, an approach is developed to allow better definition of the fracture characteristics. More realistic models are used to analyze the pressure data recorded during well tests. This is made possible by integrating additional data, in particular, the frac and pack placement data. Problem Definition and Solution Approach Published well test data performed following frac and pack completions, commonly show homogeneous with wellbore storage and skin behavior5–10. The skin values generally reported range between −2 and 10 and are used as an indicator of completion effectiveness. Non Darcy effects are usually negligible in the range of commonly observed production rates. A study summarizing published results11,12 of 150 completions, concluded that the average skin value following frac and pack treatments was close to +3. It follows that the fracture is completely masked and its characteristics cannot be determined using the homogeneous well test model and including the effects of wellbore storage and skin. It is common practice in interpretation to choose the simplest model for a first pass interpretation. However, it is also good practice to verify consistency of the model chosen with additional data available. Geology, logs and core data are used to build a preliminary fracture placement model. This model is then calibrated against in-situ measurements to ensure it is a realistic representation of the formation. The calibrated model serves to design the fracture placement and also to analyze the placement data and determine the fracture characteristics.