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The conventional drilling fluid to drill the high-temperature wells are non-aqueous fluid. ADNOC used high-temperature water-based drilling fluid instead of nonaqueous fluid to drill the well successfully. High-temperature water-based drilling-fluid systems hold several advantages over non-aqueous systems from financial and environmental viewpoints. However, most conventional water-based systems start to become unstable at temperatures above 300 degF. This paper details the design and implementation of specially designed water-based drilling fluids based on custom-made branched synthetic polymer that meet these temperature stability requirements. The branched synthetic polymer exhibits superior rheological properties and fluid loss control, as well as longterm stability above 400 degF. Under static conditions, the high-temperature fluid shows no gelation, resulting in lower swab surge pressures while the stability of the highly branched synthetic polymer and enhanced rheological profile minimize sag. ADNOC required a cost-effective drilling-fluid system that remains stable under static temperatures expected to exceed 375 degF. The longterm stability of the system was critical for successful wireline logging operations. In addition, the system was required to provide shale inhibition, hydrogen sulfide (H2S) suppression and enough density to maintain well integrity while drilling through anticipated high-pressure zones. The challenging intermediate and reservoir sections were drilled and evaluated using high temperature water-based system. This paper will discuss the successful execution of high temperature water-based system in one of high-temperature well in ADNOC field.

Amine shale inhibitors are an integral part of high-performance water based mud (HP WBM). There are many commercially available amines with similar claims regarding performance as shale inhibitors. Most performance comparisons are made relative to KCl-polymer muds, making the shale inhibitor differences very apparent. Unfortunately, a comparison between several good-performing inhibitors is rarely performed and reported. There are few systematic comparisons of amine shale inhibitors with each other based on their structure and conditions under which testing is performed. The relationship between amine structure and performance as an inhibitor is not well understood. This paper presents design of an experimental methodology to compare the effectiveness of 30+ amines as shale inhibitors under a broad range of testing conditions. Shale hydration, dispersion, and bulk hardness were measured after exposure to drilling fluids to determine which test parameter can most efficiently distinguish amines. Additionally, the adsorption or desorption of amines from a clay were measured to determine which amine is the strongest absorber. Statistical data treatment was applied to separate signal from the noise of measurements. The results of this investigation verified that amine inhibitors do not affect shale moisture content and shale dispersion is primarily affected by fluid viscosity. Furthermore, a bulk hardness test that measures cuttings hardness is a good differentiator of amine inhibitors. Supplementary functioning for amine inhibitors was confirmed with adsorption or desorption test that showed good correlation with a bulk hardness test. In summary, these measurements established a structure-activity relationship between the amines tested and determined that an effective shale inhibitor should contain more than 1 nitrogen atom/molecule. Additionally, linear structure is preferred over branched structure, and supplementary hydrophobic amines function better than hydrophilic amines provided the amine remains water soluble. Amines were further differentiated by their acid-base dissociation constant (pKa). The reason some amines perform in broader pH range than others is also presented. For the first time, a statistically validated study has been conducted to assess the results of different tests and to compare the effectiveness of different shale inhibitors. The results of these comparisons provided a way to understand the shale inhibition mechanism and develop better practices focused on developing next-generation aqueous fluid systems.

High-temperature water-based drilling fluid systems hold several advantages over synthetic based systems from financial and environmental viewpoints. However, most conventional water-based systems start to become unstable at temperatures above 300 degF. This paper details the design and implementation of A Novel Water-Based Drilling Fluid that meet these temperature stability requirements. The newly developed high-temperature water-based system discussed in this paper utilizes a custom-made branched synthetic polymer that exhibits superior rheological properties and fluid loss control as well as long term stability above 400 degF. The branched synthetic polymer is compatible with most oilfield brines and maintains excellent low-end rheology necessary for hole cleaning and solids suspension under high-temperatures and pressures. Under static conditions, the high-temperature fluid shows no gelation resulting in lower swab surge pressures while the stability of the highly branched synthetic polymer and enhanced rheological profile minimize sag. To drill a challenging exploration well, a Middle East client required a cost-effective drilling fluid system which remains stable under static temperatures expected to exceed 375 degF. The long-term stability of the system was critical for successful wireline logging operations. In addition, the system was required to provide shale inhibition, hydrogen sulfide suppression and sufficient density (above 16.5 lbm/galUS) to maintain well integrity while drilling through anticipated high-pressure zones. The challenging intermediate (12.25-in and 8.375-in) and reservoir (6-in) sections were successfully drilled and evaluated using this new branched synthetic polymer-based system. Fluid property trends and system treatments will be detailed alongside thermal stability data for extended periods required for wireline logging (up to 9 days static). This paper will discuss how proper laboratory design of the high-temperature water-based system was translated to excellent field performance and will indicate how this technology can be utilized for future campaigns in the region and worldwide.