The use of invert emulsion drilling fluids as a key enabler to successfully drill extended reach wells and access hydrocarbons that were previously out of reach has been common practice across the industry for decades. One of the more recent, but less frequently discussed, topics is how to effectively design a solids-free, brine-based completion fluid to facilitate the running of the completion by reducing torque and drag. The choice of lubricant for brine-based completion fluids is primarily driven by technical performance, both in terms of torque reduction and compatibility with the brine, potential brine contaminants, such as divalent ions, invert emulsion drilling fluid, and crude oil that may be encountered in the field. During the planning phase for a recent ultra-extended-reach drilling campaign located offshore Sakhalin Island, it was highlighted that, without a lubricant in the completion brine, neither the upper nor the lower completion would be able to reach the required total depth, based on historical friction factor data. The brine planned for use as a completion fluid must demonstrate lubricity features near that of an invert-emulsion drilling fluid for the well to be completed successfully. This paper summarizes the laboratory test results to validate the lubricant selection and provides details about the operational procedures and results achieved after using the new lubricant in the field for the first time.

A combination of divalent base brine and high wellbore temperature presents significant challenges for high density aqueous reservoir drilling fluids. Such systems traditionally use biopolymers as viscosifiers; however, they are subject to degradation at elevated temperatures. Non-aqueous drilling fluids are thermally stable but complete removal of the filtercake is challenging and this can lead to formation damage. This paper describes the qualification and first deepwater drilling application of a unique aqueous reservoir drilling fluid at temperatures above 320°F. A high-temperature divalent brine-based reservoir drilling fluid (HT-RDF) and a solids-free screen running fluid (SF-SRF) were designed, both utilizing the same novel synthetic polymer technology. Calcium bromide brine was selected for use to minimize the total amount of acid-soluble solids in the drilling fluid. A comprehensive qualification was undertaken examining parameters such as rheology performance across a range of temperatures, long-term stability, fluid loss under expected and stress conditions (16 hours at 356°F), production screen test (PST), and various fluid-fluid compatibility tests. Return permeability tests were conducted on the final formulations to validate their suitability for use. The synthetic polymer technology provided excellent rheology, suspension, and fluid loss control in the fluid systems designed in the laboratory. To prepare for field execution multiple yard mixes were performed to verify the laboratory results on a larger scale. Additionally, a flow loop system was utilized to evaluate fluid performance under simulated downhole temperature and pressure conditions before field deployment. The final high temperature drilling fluid as designed provided rheological properties that met the necessary equivalent circulating density (ECD) requirements while drilling the reservoir. The fluid loss remained extremely stable and there were no downhole losses despite the depleted nature of the wellbore. Production screens were run straight to total depth (TD) with no wellbore stability issues after a three-day logging campaign. High temperature aqueous reservoir drilling fluids have historically been limited by the lack of suitable viscosifiers and fluid loss control additives. This paper outlines the design, mixing and logistical considerations and field execution of a novel polymer-based reservoir drilling fluid.

During recent years there has been a significant increase in the use of filter cake removal systems that involve in-situ release of formic or lactic acid during the clean-up stages of the reservoir section, particularly in limestone formations. Furthermore, there have been opportunities to compare the field performance of these relatively small applications of weak, organic acids with significantly larger application volumes of highly concentrated hydrochloric acid (HCl). Surprisingly, some results showed that the smaller volumes of the weaker, organic acids could have equivalent or better performance than that produced by the more traditional HCl-based treatments. In particular this relationship was also observed in cases where the volume of HCl applied had significantly greater power to dissolve limestone than was the case for treatment with the more successful organic acid. It is well known that productivity of wells in carbonate reservoirs is usually greatly improved by treatments designed to remove the filter cake and the low-permeability zone created by the drilling process, but it is not obvious why smaller volumes per foot of weak organic acid should be more effective than larger volumes per foot of stronger and more concentrated mineral acid. It has been observed that the acid precursors which release the in-situ acids are applied to the formation in a neutral condition. The paper discusses the implications of using neutral acid precursors, and laboratory data is presented showing the effects of such treatments on the near-wellbore matrix permeability.

Injector wells comprise a small portion of the wells drilled globally; however, they pose unique drilling fluid challenges. Required for pressure support and production maximization, these wells can be costly if the desired level of injectivity cannot be achieved without first flowing them back. Traditional drill-in fluids (DIFs) contain starch and xanthan, the latter is known to impair injectivity due to its poor acid solubility. This paper describes the development of an aqueous reservoir drilling fluid targeted for injector wells. A brine-based reservoir drilling fluid was designed and developed utilizing a novel dual-functional xanthan-free additive to provide the necessary rheological and fluid loss properties without impairing injectivity. A thorough qualification was undertaken to evaluate fluid performance under a variety of conditions. Properties investigated included rheology, static-age stability, fluid loss, lubricant compatibility, and contamination susceptibility. A delayed-action filter cake breaker fluid was also designed and tested for suitability with the new reservoir drilling fluid. Return injectivity measurements were performed on both aloxite discs and core plugs to simulate the ability to achieve matrix injection without flowback. The novel additive provided excellent rheology, suspension, fluid loss control in the reservoir drilling fluid tested in the laboratory. Return injectivity testing demonstrated that the new DIF significantly outperformed existing fluids that contain xanthan or diutan without adjusting the delayed-action breaker formulation. The rheological performance of the new fluid was found to be stable and can be adjusted either though the novel additive concentration itself or through particle size optimization. Evaluation of the spent filter cake breaker effluent demonstrated that the novel additive was fully degraded, as compared to the traditional DIF in which an iodine test indicated the presence of whole starch persisting after several days contact with low-pH breaker. Existing DIF solutions function adequately for oil and gas producing wells given the low lift-off pressure resulting in minimal impairment to productivity. When considering injection wells, superior performance was achieved using this newly developed DIF which provides the potential to reduce well construction costs by eliminating the requirement to flow reservoir fluids back to a production facility before injecting.