The Jurassic reservoirs of deep wells in Kuwait have traditionally been drilled with OBM. Barite is utilized as the weighting material in the OBM resulting damages to these reservoirs, thereby reducing the productivity to a significant extent. The higher oil to water ratio (95/5) of OBM limits the possibilities of identifying the micro fractures in reservoirs due to the limited conductive medium in OBM. Potassium formate WBM, with Manganese Tetraoxide as weighting material was successfully applied in HPHT wells overcoming these limitations. K-Formate brine was utilized up to maximum density of 12.5 ppg to reduce the impacts of solids in the mud. For the first time, maximum mud weight of 17.8 ppg was achieved operationally using micromax (Mn3O4) in this WBM. Also, for the first time in Kuwait, this kind of fluid was used to drill the section with the inclinations above 60° in deep wells. As a result of using K-Formate WBM in the reservoir sections, production increased significantly when compared to the wells drilled with OBM and barite. Wells were simulated easily without the presence of barite. Water based conductive medium gave better quality of image logs. Unlike other WBM's, K-formate WBM was stored for long periods, over a year in the mud plants without any damage to the mud properties. Recycling reduced the overall fluid costs in the subsequent wells drilled with K-formate WBM. Environmental damage due to the OBM spills and cuttings were completely avoided; K-formate WBM is highly bio-degradable under atmospheric conditions and is environmentally friendly. The experience and success gained with its use on the initial wells led to the planned usage of this WBM on all deep exploratory wells. This paper explains the experiences gained and the achievements made over the years with K-formate WBM used for drilling the deep HPHT wells.
Drilling in North Kuwait presents significant challenges due to the hard rock in the overburden that needs to be drilled in large hole sizes en route to the targeted deep Jurassic reservoirs. A project was taken up in order to improve the drilling performance (especially Rate of Penetration, ROP) thought the hard layers located in three upper sections of the wells (28,″ 22″ and 16″) by implementing the "Drilling Efficiency Optimization" (DEO) methodology. DEO is an overall process to improve drilling performance by increasing ROP and bit footage through the utilization of efficient drilling practices throughout the planning, execution, and post-drilling phases. This paper describes the strategies, practices and "Driller Roadmaps" that were developed to improve ROP and drilled footage on the three sections of interest. The drilling parameters and results from three trials implementing the proposed improvements are also included. Field data demonstrates that by optimizing BHA (Bottom-Hole Assembly) design, bit hydraulics and drilling parameters through DEO process, the ROP was improved by over 70% on average in the three hole sections in which the trials were conducted. Also, due to the ROP improvement and longer bit run durations, a total of 17 rig days was saved. One bit established a new record for the longest 22″ TCI bit run ever achieved in North Kuwait (total footage: 2883 ft). Furthermore, the entire 16″ section was drilled using only two PDC bits, for the first time ever. The paper also provides recommendations on the next steps in DEO implementation to further improve drilling performance in North Kuwait wells. The insights provided in this paper will assist KOC in their endeavours to improve the overall drilling performance in their operations, especially drilling hard rock. The lessons learned have led to best practices being developed for the North Kuwait wells and serve as a valuable benchmark for projects located in the vicinity.
Deep wells drilled into the Jurassic formations of North Kuwait pose a drilling challenge due to the existence of low pressure reservoirs separated by an extremely high pressure salt zone. Currently, the seven string casing design in these wells leaves no further option for zonal isolation. As a result, a wide range of pore pressures are encountered while drilling these formations. Depleted zones/reservoirs in these wells suffered multiple instances of differentially stuck pipe and side tracks. The end result has been a significant loss of expensive rig days. These sections are drilled using oil based mud (OBM) with a high oil/water ratio and mud densities ranging from 10 to 17 ppg.To prevent a reoccurrence of the differential sticking problems, extensive laboratory work was undertaken to determine how to negate the effects of high differential sticking force while drilling depleted zones. Laboratory tests and fracture modelling based on historical data were carried out to develop a suitable fluid formulation to address these challenges. This work indicated that a novel combination of glycolic polymer lubricant and sized marble bridging agent provided the optimum combination of lubricity and filtration control to minimize differential sticking tendency.A fluid formulation based on the laboratory results was utilized to drill subsequent wells in this field. The depleted intervals were drilled using a similar OBM treated with a combination of unique lubricant and sized marble bridging agent to reduce differential pressure transmission across the depleted zones. The intervals were drilled and logged without the occurrence of any problems of differential sticking. The troublesome sections were completed incident free resulting in huge savings in cost and rig time.This paper describes the historical challenges in this field and present case studies demonstrating how the solution was successfully implemented in the field.
This paper is based on continuous cement job improvements carried out for deep HPHT wells over the last ten years by KOC and their cementing service providers. The particular challenges in these complex wells compelled us to place primary attention on well construction aspects while also considering long term well production. Because of narrow annuli, dense saline water in formation situation cannot be managed with other tools like ECP/Swellables etc. Our cement slurry is designed to be pumped in place without sacrificing its intrinsic qualities. It responds in a predictable manner and confirms by testing and simulation under relevant conditions including multiple producing layers with pressure variations.KOC cementations described cover the deep wells in a depth range of 16,000 to 19,000 ft., with possible strength retrogression because of temperatures, narrow difference of pore and frac pressure, mud weight ranges of 19.5 to 20.0 ppg, three liner systems, and a seven string casing policy. Encountered difficulties have included inability to displace from the string, wet shoe track, hanger top leakage and poor quality cement sheath in the annulus.Different combination of spacers and slurry weight have been tried. Many HPHT cement additives were trialed and eliminated and new ones introduced in order to achieve success. Extensive laboratory testing and software simulation was done to finalize slurry designs. Slurries were selected to meet both drilling and production requirements. This approach will be detailed in the paper including examples. This paper will explain the criteria of selecting the most suitable slurries that comply with best practices for successful HPHT cementing. It will detail slurry selection methods for a number of practical cases including: formation fluid influences, prevention of gas migration, slurry property changes with hydrostatic pressure variations, and influence of high percentage of non-cement materials in the slurry.The subject matter of this paper is very important in deep HPHT wells slurry selection and placement. This case history is developed referencing the wells drilled in Kuwait, but the concepts will have significant relevance for application to similar wells in other regions.
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