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Data-driven, or top-down, modeling uses machine learning and data mining to develop reservoir models based on measurements, rather than solutions of governing equations. Seminole Services’ Powerscrew Liner System is a new expandable-liner hanger that is set with torsional energy from the topdrive. Stuck pipe has traditionally been a challenge for the oil and gas industry; in recent years, operators have become even more determined to reduce the effect of stuck-pipe issues. The primary purpose of this study is to develop a method that overcomes the restrictions of rock-mechanics tests with respect to unconventional shale formations. The Earth is complex in all directions, and hydrocarbon traps require closure—whether structural or stratigraphic or both—in three dimensions.
Petroleum geomechanics is defined as the interaction between the evolving earth stresses and the overburden and reservoir rock mechanical properties. A comprehensive understanding of rock mechanical behaviour is key to successful field appraisal and development. For example, 70% of the world's oil and gas reserves are contained in reservoirs where rock failure and sand production will become a problem at some point. Wellbore stability issues have been estimated to cost the industry USD 8 billion annually. A reliable and robust predictive geomechanical model - whether 1D or 3D - requires a variety of data from different sources.
Tubular structures in thermal applications are subject to unique design challenges that cannot be addressed with conventional methods. In conventional design, the structure "fails" when thermally induced loads yield the pipe, but thermal wells often must operate under such conditions and industry experience demonstrates that wells can do so reliably. Designing a structure that remains stable requires knowledge of strain-based design: the distinction between strength and stiffness, the effects of variability in strength and stiffness, load path dependencies, post-yield material behavior, and strain localization. Collateral considerations for resistance to environmental effects, geomechanical loads and production management can also challenge intuition developed in conventional well design. In this course, participants will learn to "think strain, not stress" for well structure design and gain exposure to other aspects of thermal well design.
A ceramic proppant based chemical delivery system is known to be able to deliver multiyear inhibition of scale with a onetime treatment. The delivery system can be used to replace part of the proppant in frac and frac packs completions, be used as the gravel in gravel packs, or simply as a transport mechanism to place production chemicals in an acid-frac stimulated reservoir. This chemical delivery system has been recently applied offshore Congo for the first time. Learnings from the implementation of this technology both onshore and offshore in the United States have enabled the product usage to expand internationally. The use of this delivery system has eased the operational challenges seen in offset wells caused by repeated treatment of scale inhibitor. Increased space has been freed on the platform and all interventions for scale control have been eliminated. Results presented in this paper will include the design of this work for the application in Congo, including infusion and release of the inhibitor from the ceramic carrier and design of the control membrane to achieve the desired protection time. This design work also includes the learnings from multiple other applications that were combined for this new area of implementation, including case histories from other basins. This paper will be beneficial for production engineers who desire a cost effective solution to deploy production assurance chemicals in a onetime treatment, regardless of well type, resulting in a multi-year solution.
High angle S-shaped and high displacement L-shaped well profiles are preferred now-a-days in Balimara field located in the northeast region of India. Main targets are the deep Clastic reservoirs of Oligocene age. Major events reported are while drilling against dipping formations with differential stuck pipe situations with variety of drilling complications in the unstable formations owing to shales in Tipam sandstone and thin sections of coal and shale alteration in oil bearing Barail sandstone formation. The substantial risk of wellbore instability in accessing the reservoirs with lateral variation in pore pressure threatened the commercial success of the project. This paper elaborates how geomechanical information along with BHA design and chemicals was integrated into the decision-making process during well design and drilling operations to avoid wellbore instability issues.
Wellbore stability analysis through Mechanical Earth Model was conducted using estimated state of stress and mechanical properties of the overburden and reservoirs. The model incorporated data from several sources including geophysical logs, leak-off tests, advanced sonic far field profile and drilling records collected from the earlier wells. Examination of the deviated well bore profiles suggested occurrence of ledges due to lower mud weight and improper drilling parameters while drilling alternate layers of sand, shale and coal in Barail formation. Horizontal stress contrast increases in Barail formation supporting the need of higher mud weight with increased well deviation towards specific azimuth.
The integrated geomechanical analysis provided key information: The 9 5/8" casing shoe should be set at shale layer of Tipam Bottom to isolate upper differential sticking prone sandstone layers with Barail Argillaceous sequence. This will help to drill 12.25-inch hole with 9.6 ppg-9.8 ppg only. Shale layers at Tipam bottom require 10.0-10.5 ppg, while Barail shale requires 10.5 ppg-11.0 ppg for vertical well. When the well deviation increases up to 30deg, mud weight requirement rises to 11.2 ppg-11.8 ppg. Based on analysis, the mud weight at the start of 8.5inch section was raised sufficiently to 10.5 ppg to avoid the hole collapse experienced in the earlier lower angle wells. Later, continuous review of torque and drag along with cutting analysis helped to raise mud weight up to 11.0 ppg till well TD. As a result, lower UCS shale and coal layers are drilled with minimal shear failure and improved hole condition. However, changes to the mud system were needed to limit fluid loss and avoid differential sticking across the sandstone. For deviated section, rotary BHA has been used to improve hole trajectory vs. planned with lesser ledges. Downhole hydraulics has been maintained with proper flow rate and rpm to main hole cleaning. The new well engineered with the integrated geomechanics information has been drilled from surface to extended TD while saving 15 rig days.
The horizontal wells that are completed with slotted liners often suffer from a severe water production problem, which is detrimental to the oil recovery. This is because the annulus between the slotted liners and wellbore cannot be fully filled with common hydrogels with poor thixotropy, which determines the ultimate hydrogel filling outcome in the annulus. This paper presents a novel hydrogel with high thixotropy to effectively control water prod uction in the horizontal wells.
In this work, a new double-group cross-linking hydrogel with high thixotropy was developed. The hydrogel was generated through the graft copolymerization of acrylamide onto polysaccharide and the covalent cross-linking reaction between acrylamide and N, N-methylene bisacrylamide. Nano-laponite and organic titanium were employed as the thixotropic agents. This study aimed at evaluating the thixotropic performance, gelation time, and plugging efficiency. The thixotropic mechanisms of the new hydrogel were also investigated by measuring its rheological properties and examining its microstructures.
It was found that the new hydrogel became thickened rapidly after shearing. Its thixotropic recovery coefficient was 0.734, which was much higher than those for the traditional hydrogels. Visual observations also indicated that this hydrogel had excellent thixotropy. The gelation time can be controlled in the range of 2-8 h by properly adjusting the concentrations of the framework material, cross-linker, and initiator. The hydrogel could be customized for the mature oil reservoirs, at which it was stable for over 90 days. A series of laboratory physical modeling tests showed that the breakthrough pressure gradient and the plugging ratio of the hydrogel were higher than 9.5 MPa/m and 99%, respectively. The freeze-etching SEM examinations indicated that the hydrogel had a uniform grid structure, which can be broken easily and restored quickly. This led to the remarkable thixotropic performance. The formation of a metastable structure caused by the electrostatic interaction and coordination effect was considered to be the primary reason for the high thixotropy.
The successful development of the new thixotropic hydrogel not only helps to control water production from the horizontal wells but also furthers the thixotropic theory of hydrogel. This study also provides technical guidelines for further increasing the thixotropies of drilling fluids, fracturing fluids and other EOR polymers that are commonly used in the petroleum industry.