Brines are preferred to solids-laden fluids for completion operations due to their solids-free nature, which helps preserve formation permeability. Salt selection is mostly driven by the density that must be reached to match downhole pressure requirements. When density must be above 14.2 lbm/gal (1.7 s.g.), and crystallization must be prevented, previous options were limited to calcium bromide brines, zinc bromide brines and cesium formate. These brines have severe limitations: zinc brines can be harmful to oilfield personnel and the environment, cesium formate brines are cost-prohibitive and not readily available and calcium brines cannot meet deepwater crystallization requirements. A new brine technology has been developed, that is zinc-free and extends the density of conventional bromide brines beyond their theoretical limits. This new technology addresses the limitations listed above, while providing low True Crystallization Temperature (TCT) and Pressurized Crystallization Temperature (PCT) to perform in deepwater and cold weather applications. This paper summarizes the completion fluid properties, laboratory qualification and verification, and summarizes recent successful field applications of the new high-density zinc-free brine.

Cross-domain data analysis is arguably the most important part of oilfield data analytics. While it enables holistic process optimization, it is also challenging to execute. Data are often scattered across different databases making it complex to join and may require multidomain expertise to properly analyze. Here, processing and analysis of data collected by three well construction business lines of the same service company were performed to establish a link between drilling fluid properties and drilling performance. The data engineering workflow starts by taking information from a single service company and combining that information about drilling operations, drill bits, and drilling fluids into a single dataset. Metadata including locations, operators, and wells are then mapped, and overlapping attributes are unified and reconciled. Data is further processed to extract relevant drilling performance metrics and drilling fluid properties and then labeled by well, section, and drilling run. The resultant data workflow enables detailed analysis, focusing on particular locations, drilling practices, hole conditions, and fluids. The joined, cleaned, and processed dataset includes information from thousands of wells drilled globally since 2016. The datasets from different sources differ in the level of detail, but are complementary to each other, providing a broader picture when merged. The data is organized and visualized on dashboards, enabling in-depth analysis through intuitive filtering on a variety of conditions. These conditions may include location, drilling run type, depth, used drill bits and tools, and drilling fluid type and properties. The main drilling performance metrics are distance drilled per run and run duration. These are used to calculate the run average rate of penetration (ROP). Reasons for pulling out of the hole (POOH) and risks for POOH are extracted from text comments of the daily drilling reports. This enables the tracking of abnormal run terminations due to drilling tool failures. It also enables tracking of wellbore integrity, and substandard drilling and hole conditioning practices, especially at section total depth (TD) or because of drilling fluid issues. Aggregated metrics of minimum, maximum, and median are used for high-level data evaluation. Statistical significance of effects and causality are analyzed in detail on selected cases. Based on the data, several examples of such analyses are created that focus on the effects of water-based fluid vs. oil-based fluid, on drilling performance in the major oil fields in the United States. Holistic analysis of the effects of drilling fluids on drilling performance becomes possible through the well construction cross-domain data fusion. The developed workflow enables analysis of drilling fluid-related big data, covering tens of thousands of wells globally. The analysis results are expected to improve drilling efficiency and reliability and ultimately reduce operators' total well expenditures.

Deepwater operators are now exploring new fields that require products and services to be at the forefront of technology. This is especially true in the Gulf of Mexico, where fields with pressure gradients higher than previous developments are particularly demanding. In the coming decade, the Gulf of Mexico will see the first development using equipment rated at 20,000 psi. In such fields, density requirements for drilling fluids regularly exceed 15 lbm/gal, and can surpass 16 lbm/gal. Despite being green fields, narrow drilling windows can be expected, which can prove challenging when optimizing rheology at such mud weights. The South Platte field operated by TotalEnergies faced this challenge after a long absence in the Gulf of Mexico. This paper presents the design, planning, and field execution for drilling fluids of the South Platte deepwater exploratory well in the Gulf of Mexico. The operator drilling team was anticipating several challenges for what would be its deepest well ever drilled, such as, the need of high-density mud (above 16 lbm/gal), with potential side effects such as fluids stability over long static periods, and potential drilling window limitation equivalent circulating density (ECD margin). The selected high-performance invert emulsion fluid (HPIEF) was designed to address these challenges. Facing one of the most active hurricane seasons on record, with 30 named storms, multiple well suspensions were necessary (6 well suspensions, 4 BOP disconnections). This eventually led to static periods greater than the 15-days stability at downhole conditions. Those periods were targeted at the design stage.