Xanthan gum (XG) was widely used as an oilfield chemical treatment agent because of its environmental protection and diverse functions. With the increased drilling depth and formation complexity, the shortcomings such as poor solubility and low resistance to temperature were gradually exposed. In this study, a modified XG derivative XG-g-AAA was synthesized by grafting XG with acrylic acid (AA), acrylamide (AM), and 2-acrylamido-2-methylpropane sulfonic acid (AMPS). The chemical structure of XG-g-AAA was determined by Fourier transform infrared spectroscopy and nuclear magnetic resonance (¹H NMR). Then, the solubility, high-temperature rheology and filtration properties, resistance to Na⁺/Ca²⁺, and compatibility were investigated. Results show that (1) both in aqueous and salt solutions, XG-g-AAA can completely be dissolved within 15 min. The significant improvement of the solubility of XG-g-AAA makes it more suitable for field use. (2) XG-g-AAA is less sensitive to high temperatures, and the viscosity decay decreased by 23.3 and 21.3% than XG at 150 and 180 °C, respectively. XG-g-AAA-based drilling fluid is a high-quality drilling fluid with significant shear thinning behavior, and the power-law model is the optimal model to describe its high-temperature rheology. Within 150 °C, 1.5% XG-g-AAA can maintain a reasonable value of the flow behavior index (n) (0.55–0.69), filtration volume (<11.6 mL), and sufficient gel strength (GS). At 150–200 °C, 3% XG-g-AAA is recommended. The value of n was in the range of 0.45–0.62, and the fluid loss was within 10 mL. However, 3% XG-g-AAA cannot provide enough GS at 200 °C; thus, a shear strength-improving agent is recommended to be added. (3) XG-g-AAA showed excellent contamination tolerance and compatibility. It could resist 2 wt % CaCl₂ and 35 wt % NaCl at room temperature and 0.75% CaCl₂ and 5% NaCl after 150 °C aging. (4) XG-g-AAA showed compatibility with sulfonated drilling fluids and could replace commercial fluid loss agents in the formula. Furthermore, the high-temperature fluid loss control mechanism was discussed by analyzing the effects of XG-g-AAA on the bentonite layer spacing, particle size distribution, stability of the colloidal system, and mud cakes.

The flow of groundwater and the interaction of buried pipe groups will affect the heat transfer efficiency and the distribution of the ground temperature field, thus affecting the design and operation of ground source heat pumps. Three-dimensional numerical simulation is an effective method to study the buried pipe heat exchanger and ground temperature distribution. According to the heat transfer control equation of non-isothermal pipe flow and porous media, combined with the influence of permeable groundwater and tube group, a heat-transfer coupled heat transfer model of the buried pipe group was established, and the accuracy of the model was verified by the sandbox test and on-site thermal response test. By processing the layout of the buried pipe in the borehole to reduce the number of meshes and improve the meshing quality, a three-dimensional numerical model of the buried pipe cluster at the site scale was established. Additionally, the ground temperature field under the thermal-osmotic coupling of the buried pipe group during groundwater flow was simulated and the influence of the head difference and hydraulic conductivity on the temperature field around the buried pipe group was calculated and analyzed. The results showed that the research on the influence of the tube group and permeable groundwater on the heat transfer and ground temperature field of a buried pipe simulated by COMSOL software is an advanced method.

Drilling fluid lubricants guarantee safe and fast drilling. When drilling high-temperature or NaCl/CaCl2-containing formations, there is an urgent need to develop environmentally friendly lubricants that are resistant to high temperature and ionic contamination. In this study, a deep eutectic solvent (DES) ChCl-PEG lubricant for a water-based drilling fluid was designed and prepared. ChCl-PEG is a kind of biodegradable material with high thermal stability formed by hydrogen bonding between choline chloride (ChCl) and polyethylene glycol (PEG). Within 240 °C, ChCl-PEG significantly improved the lubricating properties of drilling fluids and mud cakes. The lubrication coefficient (K) was controlled within 0.2, and the reduction rate of the adhesion coefficient (Δf) was higher than 40%. The salt and calcium resistances of ChCl-PEG at high temperature (150 °C) are as high as 36% NaCl and 20% CaCl2. Under these conditions, ChCl-PEG maintains a low value of K: 0.097–0.157 (5–36% NaCl) and 0.145–0.162 (5–20% CaCl2), respectively. Also, it maintains higher values of Δf, which can reach up to 51.6% and 80%. The lubricating mechanism of ChCl-PEG can be summarized as the adsorption of ChCl and the formation of a large number of hydrated molecules.

An urgent problem of geothermal energy source development is how to cut down the production costs. The use of temporary sealing materials can reduce the costs associated with the circulation lost by plugging, and increase the production by self-degradation. Based on the utilization of starches as self-degradable additives in the medical field, this paper investigated the effects of three kinds of starches, namely corn starch (CS), hydroxypropyl starch (HPS) and carboxymethyl starch (CMS) on the properties of alkali-activated cement (AAC). In addition, the thermal properties of starch, the compressive strength and microstructures of the cement with starch were tested, to evaluate the potentiality of starch as self-degradable additive for geothermal cement. The analysis showed that: (1) all the starches have the effect of increasing the apparent viscosity, prolonging the setting time and reducing the static fluid loss of alkali-activated cement; (2) the addition of starch increased the number of pores in 200 °C-heated cement, facilitated the leaching process, and thus promoted the self-degradation; and (3) among the three starches, CMS has the most potential as a self-degradable additive.

The accurate control of the wellbore pressure not only prevents lost circulation/blowout and fracturing formation by managing the density of the drilling fluid, but also improves productivity by mitigating reservoir damage. Calculating the geothermal pressure of a geothermal well by constant parameters would easily bring big errors, as the changes of physical, rheological and thermal properties of drilling fluids with temperature are neglected. This paper researched the wellbore pressure coupling by calculating the temperature distribution with the existing model, fitting the rule of density of the drilling fluid with the temperature and establishing mathematical models to simulate the wellbore pressures, which are expressed as the variation of Equivalent Circulating Density (ECD) under different conditions. With this method, the temperature and ECDs in the wellbore of the first medium-deep geothermal well, ZK212 Yangyi Geothermal Field in Tibet, were determined, and the sensitivity analysis was simulated by assumed parameters, i.e., the circulating time, flow rate, geothermal gradient, diameters of the wellbore, rheological models and regimes. The results indicated that the geothermal gradient and flow rate were the most influential parameters on the temperature and ECD distribution, and additives added in the drilling fluid should be added carefully as they change the properties of the drilling fluid and induce the redistribution of temperature. To ensure the safe drilling and velocity of pipes tripping into the hole, the depth and diameter of the wellbore are considered to control the surge pressure.