Options Reduce Nonproductive Time in Drilling Unconventional Horizontal Wells

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 23567, “Effective Options Used To Reduce or Eliminate Nonproductive Time in Case of Severe and Total Losses While Drilling Unconventional Horizontal Wells,” by Salahaldeen S. Almasmoom, SPE, Ahmad I. Al-Mugdad, SPE, and Guoqiang Yin, SPE, Saudi Aramco, et al. The paper has not been peer reviewed. Copyright 2024 International Petroleum Technology Conference. _ The horizontal wells in an unconventional area of interest are designed with combined 8½-in. vertical/curve/lateral sections. The section typically is drilled with oil-based mud (OBM). Severe to total losses might occur while drilling through potential loss zones in the vertical section. By applying the presented practices in the complete paper, the losses are cured successfully in most cases to allow drilling ahead to well total depth (TD) in less time than when using conventional approaches. The results are less overall risk, less nonproductive time (NPT), and more cost savings when compared with traditional methods. Introduction The unconventional area of interest has an optimized casing design of four casing strings. This casing design is achieved through combining multiple drilling potential trouble zones and, therefore, combining multiple formations with different mud-weight (MW) requirements, different fracture gradients, and different geological features. The main well design improvement consists of the combined vertical, curve, and lateral sections in one 8½-in. section. Combining the sections, however, means drilling through different potential trouble zones to land the well in the sweet zone of the target T2 formation and then geosteering the lateral section in the sweet spot to well TD. Handling the lithology variation among the formations is the main challenge. The 8½-in. section consists of nine formations. The section starts with thick body of anhydrite. A potential water-bearing limestone stinger exists at the lower part of the anhydrite section (Formation H1), requiring higher-than-normal MWs in some areas. Furthermore, fractured dolomitic limestone section underlies the anhydrite section (Formation A). The lower Member D of this formation has the most natural fractures, the highest porosity, and the highest permeability because it is a depleted reservoir. When landing the well, Formation T2 features naturally fractured overpressured, low-permeability mudstones. The formations from J1 to T2 embody operational risks and difficulties. The focus of this paper is Member D of Formation A. Experiencing partial, severe, or total loss of circulation while drilling through or below Formation A, Member D might occur as the result of the following operational factors: - Entering with higher MW (110-120 lbm/ft3 vs. planned 85 lbm/ft3) as the result of having water flow in the H1 formation or drilling close to a hydraulically fractured lateral - Entering with uncontrolled high instantaneous rate of penetration, which can reach as high as 500 ft/hr when drilling with full parameters - Drilling with high flow rate, causing very high equivalent circulating density - A high incidence of natural fractures, causing a fracture gradient lower than 85 lbm/ft3