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In its Sixth Edition, this book has been updated and revised to incorporate new information on technology, economic, and political issues that have impacted the use of fluids to drill and complete oil and gas wells. With updated content on completion fluids and reservoir drilling fluids; health, safety and environment; drilling fluid systems and products; new fluid systems and additives from both chemical and engineering perspectives; wellbore stability, adding the new R&D on water-based muds; and equipment and procedures for evaluating drilling fluid performance in light of the advent of digital technology and better manufacturing techniques, this book has been thoroughly updated to meet the drilling and completion engineer's needs.

Completion fluids play a vital role in well-related processes within the oil extraction industry. This article presents a comprehensive study of the properties and performance of various brine solutions as completion fluids for different well and reservoir conditions. Attributes examined include density, corrosion resistance, temperature stability, compatibility with formation fluids, clay swelling potential and influence on wettability. The research highlights the significance of selecting appropriate completion fluids to optimize well and reservoir operations. Zinc chloride emerges as an excellent option for high density applications, while sodium chloride and potassium formate solutions are ideal for extreme cold conditions. Potassium acetate outperforms calcium chloride and potassium chloride and has excellent pH stability. The compatibility of completion fluids with formation water has been observed to be excellent, with no sedimentation or emulsion formation. Potassium acetate also experiences minimal clay swelling, making it suitable for clay-rich formations. On the other hand, calcium chloride has a higher clay swelling than most of the brines tested, making it less suitable for sandstone formations with a higher clay content than these brines. The research evaluates the water-wetting abilities of completion fluids in carbonate and sandstone formations. Potassium chloride and zinc chloride have the most significant impact in carbonate formations, while potassium acetate and potassium formate excel in sandstone formations. This study provides a comprehensive understanding of completion fluids, facilitating informed decisions that maximize operational efficiency, protect reservoir integrity, and enhance hydrocarbon recovery. The appropriate selection of completion fluids should align with specific well and reservoir conditions, considering the priorities of the application.

Calcium-nitrate-based transparent completion fluids are widely used in the oil and gas industry for well completion and stimulation operations in carbonate reservoirs. These fluids have many advantages, such as medium density, low corrosion, good temperature stability, low clay swelling, and high wettability. However, the density of calcium nitrate brine is limited by its solubility, which can be increased by the addition of alcohols. This study investigated the effects of adding different types of alcohols (G1, G2, and G3) to calcium nitrate brine on the properties and performance of the completion fluid for carbonate reservoirs. The fluid properties and performance were evaluated through a series of laboratory tests, including density measurement, corrosion test, viscosity measurement, rheology test, temperature stability test, clay swelling test, wettability test, and compatibility test. The results showed that the addition of alcohols to brine can improve or reduce the fluid density, viscosity, corrosion, temperature stability, clay swelling, wettability, and compatibility, depending on the type and amount of alcohols. The optimum fluids have been selected based on their highest density, lowest viscosity, lowest corrosion, highest temperature stability, lowest clay swelling, highest wettability change, and highest compatibility with formation fluids. The densities of the fluids CN 4 , CNG1 4 , CNG2 4 , and CNG3 4 were respectively 96, 101, 101.5, and 100 pounds per cubic foot (pcf). Their rates of corrosion on L80 steel were respectively 0.829, 0.589, 0.720, and 0.599 mils per year (mpy). Their apparent viscosities at 62.4 °F were respectively around 15, 120, 100, and 60 centipoise (cp). Their apparent viscosities at 176 °F were all around 10 to 25 mpy. The fluids remained clear with no evidence of suspended solid particles at 20 °F, indicating their resilience to low-temperature conditions and suitability for use in cold weather operations. The fluid CNG2 4 becomes cloudy at 285 °F, and the fluid CNG3 4 becomes cloudy from 212 °F onward, but the CN 4 fluid remains clear and transparent at all temperatures. In the tested high temperatures, the effect on their pH was around the same. The fluids CN 4 , CNG2 4 , and CNG3 4 had a lower swelling index than 5 ml per 2 g of bentonite clay. The contact angles of oil and carbonate-type thin sections after their wettabilities were affected by the fluids were also 99.5, 36.54, and 46.03°, respectively. Finally, they’re all relatively compatible with formation fluids. The best completion fluid for carbonate reservoirs was CNG2 4 , which contained calcium nitrate and G2 alcohol. This fluid had the best overall performance and safety of the fluids tested.

The western region of the Tarim Basin is a typical deep and ultra-deep oil and gas reservoir with complex geological conditions in China. This area includes a thick salt–gypsum layer, high-pressure brine layers, and other formations with high pressures and a complex pressure system. These geological features present challenges such as a high risk of drilling fluid contamination by formation fluids, the deep burial of subsalt reservoirs, high temperatures, and difficulty in designing drilling fluids. In this paper, by systematically screening and optimizing key additives, a diesel oil-based drilling and completion fluid system resistant to 220 °C ultra-high temperatures with a density of 2.60 g/cm3 was developed. The overall performance was evaluated. Utilizing an independently developed high-temperature emulsifier (BZ-PSE), an organically modified lithium silicate viscosity modifier (BZ-CHT), and compounded fluid loss reducers (BZ-OLG/BZ-OSL), the system maintained excellent rheological stability (yield point > 4.3 Pa) and filtration control capacity (HTHP fluid loss < 4.8 mL) even after aging at 220 °C. The system demonstrated a resistance to contamination by 30–50% composite brines, 15% salt–gypsum cuttings, and 10% cement, proving its capability to effectively handle extremely thick mud shale, salt–gypsum layers, and high-pressure brine. Field tests were conducted in wells GL 3C, DB X, Boz 13X, and Boz 3X. The results indicated that the high-temperature, high-density diesel oil-based drilling fluids and completion fluids can effectively address the technical challenges posed by wellbore instability in thick salt–gypsum layers, high-pressure brine invasion, and performance degradation under ultra-high temperature conditions, providing reliable technical support for the safe and efficient drilling of similar complex formations.

Well completion operations involve critical post-drilling processes to enable hydrocarbon extraction, where the selection of completion fluids—such as packer, workover, or fracturing fluids—plays a pivotal role in operational success. In Iran’s oil industry, high-temperature, high-pressure reservoirs necessitate high-density brines like calcium bromide. Reservoirs exceeding 300 °F and 10,000 psi (HPHT conditions) typically require completion fluids with densities above 100 lb/ft 3 . However, economic constraints and limited domestic bromine resources render such fluids prohibitively expensive, while locally available brines often lack essential completion fluid properties. This study addresses these challenges by synthesizing cost-effective, potassium-based brines using domestically sourced salts and alcohols to enhance density and performance. By incorporating alcohols (40% vol.), the crystallization temperature of medium-density brines was significantly reduced, enabling higher salt dissolution and achieving densities of 93.4, 97.8, 99.2, and 99.4 lb/ft 3 . Alcohol-free variants (93.4 and 97.8 lb/ft 3 ) and alcohol-enhanced formulations (99.2 and 99.4 lb/ft 3 ) demonstrated alkaline pH stability, low viscosity (Viscosity below 70 cP for pumping downhole using available pumps in Iran), minimal clay swelling (< 5 mL/2 g bentonite), and near-zero corrosion rates, even at 300 °F. Notably, exposure to reservoir rock altered wettability from oil-wet to water-wet, enhancing hydrocarbon recovery. Economically, these fluids leverage Iran’s accessible raw materials, offering a 40% cost reduction compared to calcium bromide. Designed primarily as packer fluids, they ensure well integrity under high reservoir pressures while mitigating formation damage. This research presents a scalable, sustainable solution for Iran’s oil sector, balancing technical efficacy with economic viability in challenging downhole environments.

High pressure and high temperature (HPHT) reservoirs have challenging environments for a successful completion program. Generally, low to mid-density range brine-based completion fluids (CF) are commonly used in petroleum reservoirs. Nowadays, the oil and gas drilling industry is moving toward clear high-density completion fluids at HPHT reservoir conditions. Completion fluid is used to complete an oil and gas well. It is positioned in the well to ease final operations before the start of production. These operations involve tasks like installing screens, production liners, packers, downhole valves, or performing perforations in the producing zones. We have experimentally investigated the completion fluid for stability, solid free, low viscosity, and low precipitation to ensure that it has all the desired properties. We have formulated a high-density specific gravity (1.61) completion fluid using Magnesium bromide (MgBr 2 ) in an aqueous medium. The results show that the alkaline pH value of 7.18 and solid free fluid system provide a suitable completion fluid to keep corrosion rates acceptably low. The high density of the completion fluid is an essential parameter for pressure maintenance during well control events. Our experimental results are obtained for different ranges of temperature and pressure (i.e. temperature 25–300 °C, pressure up to 30,000 psi) using a new generation ultra HPHT rheometer. This study investigates the effect of ultra-high temperature and pressure on their rheological properties. Rheological results show that the completion fluid has a low value of apparent viscosity (1.89–6.66 mPa s), which is essential for designing completion fluid at HPHT conditions. These works are helpful in maximizing the completion fluid program for HPHT well for providing an early and timely production. Article highlights Our work is important for the development of novel high-density clear completion fluids for applications in HPHT wells across the world. This study investigates the effect of ultra-high temperature and pressure on their rheological properties. The effect of temperature on viscosity is more predominant compared to pressure. Solid-free and high-density completion fluid is crucial for well completion to minimize reservoir formation damage.

Solid-free brine completion fluids, characterized by their exceptional reservoir protection capabilities and optimal rheological behavior, are highly desirable for applications in oil and gas reservoirs and have attracted significant attention in recent decades. However, as the core component of completion fluids, the viscosifier was prone to curling or even precipitating in high-temperature, high-density inorganic salt (divalent calcium) environments, leading to failure in thickening performance. In this study, a micro-crosslinked amphoteric viscosifier (i.e., A-DDAS) resistant to high temperature and calcium ions was synthesized via free radical copolymerization of N,N-dimethylacrylamide (DMAA), diallyl dimethyl ammonium chloride solution (DMDAAC), 2-acrylamido-2-methylpropane sulfonic acid (AMPS), [2-(methacryloyloxy) ethyl] dimethyl-(3-sulfopropyl) ammonium hydroxide (SBMA), and pentaerythritol triallyl ether (APE). The molecular structure and physicochemical properties of the copolymer were systematically studied by NMR, FTIR, XPS, TGA and XRD. Rheological experiments demonstrated that calcium bromide brine containing A-DDAS copolymers exhibited outstanding shear-thinning behavior and rapid thixotropic recovery, essential for efficient wellbore cleaning and fluid displacement during completion operations. As the density of calcium bromide brine increased, more calcium ions shield electrostatic attractions between the cationic and anionic moieties along the copolymer backbone, thereby promoting full extension of the polymer chains and enhancing the binding energy with water molecules. After adding 1.0 wt% A-DDAS copolymer to a 1.75 g/cm3 calcium bromide brine and aging the mixture at 180 °C for 16 h, the completion fluids exhibited an apparent viscosity of 71 mPa·s, plastic viscosity of 64 mPa·s, and yield point of 7 Pa, which were significantly better than common viscosifiers (HE300 and Dristemp). Therefore, A-DDAS copolymers demonstrated exceptional thickening capacity and dynamic shear enhancement in high-temperature, high-density calcium bromide brine, notably rendering it ideally suited for deployment in completion fluids for deep and ultra-deep wells.

There are microfractures and fractures in the carbonate formation of M oilfield, which are easy to cause collapse and borehole instability. On the basis of the liquefiable cleanflo drilling fluid system for open hole completion of horizontal wells designed in the early stage, this paper has carried out the research work of matching acidizing completion fluid system. In this paper, the influence factors, cleaning ability, compatibility, acidizing situation and protection effect of acidizing completion fluid system are evaluated in laboratory. The way of density adjustment and specific dosage of NaCl and hcoona were established to inhibit the formation of salt crystallization. HTA solid acid and JCI are used to counteract each other to reduce the corrosion of casing steel. The core displacement results show that the permeability recovery value of carbonate core after completion fluid treatment can reach 97.54%, and that of sandstone core after treatment can reach 114.7%. Moreover, the completion fluid system also has a certain acidizing effect, which can not only clean and remove the plugging, but also serve as the early induction of acidizing and stimulation.

Huabei Oilfield has a wide range of oil and gas resources. With the pressure of environmental protection and the need for high-quality and cost-effective exploration and development, cluster drilling has also put forward higher requirements. In this oilfield, there is no effective technology in large cluster reservoir, integrated design of drilling and production, surface engineering, intensive construction, recycling of drilling fluid and so on. Taking a block in Bayan as the research focus, combined with geological characteristics, and by means of experiment and theoretical analysis, this paper focuses on the optimization of wellhead layout, trajectory optimization and drilling fluid recycling technology of cluster well, and forms the cluster well drilling and completion technology that is suitable for reservoir characteristics in the target area of Huabei Oilfield, so as to achieve the purpose of reducing cost and increasing efficiency, speeding up production and construction and expanding space.