Wellhead Equipment: Essential Components for Oil Drilling

The global oil and gas drilling industry is constantly evolving and adapting to new challenges. One area that has seen significant innovation and development is wellhead equipment. This equipment is essential to ensure the safety and success of drilling projects by controlling the flow of oil and gas from the wellhead to the processing facility. In this report, we'll take a closer look at the must-have wellhead equipment in oil and gas drilling and explore the current market hotspots.

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Valves

Valves are an essential piece of equipment in any wellhead system. They control the flow of oil and gas and are designed to prevent leaks and minimize the risk of blowouts. There are many types of valves available, including gate valves, ball valves, butterfly valves, and check valves. Each type of valve has its own unique advantages and disadvantages, and choosing the right valve for your drilling project is critical. In recent years, the market for valves has expanded as companies develop new valve technologies aimed at improving safety and efficiency.

Blowout Preventers (BOPs)

Blowout preventers (BOPs) are another critical piece of equipment in wellhead systems. These devices are designed to prevent the uncontrolled release of oil and gas in the event of a blowout. BOPs come in various sizes and configurations, with some designed to operate at extremely high pressures and temperatures. In recent years, the BOP market has seen rapid growth as drilling companies focus on improving safety and reducing the risk of catastrophic accidents.

Market Hotspots

The global market for wellhead equipment is highly competitive and rapidly evolving. North America, Europe, and Asia Pacific are among the largest markets for this equipment, with demand expected to grow in the coming years. One of the key drivers of growth is the increasing demand for oil and gas, especially from emerging economies like China and India. As the demand for oil and gas increases, drilling companies are investing in new technologies and equipment to extract these resources more efficiently.

In addition, the wellhead equipment market is being driven by increased safety regulations and environmental concerns. Governments around the world are tightening safety standards and imposing new environmental regulations to reduce the impact of drilling on the environment. This has led to increased demand for wellhead equipment that can meet these standards and help drilling companies operate in a safe and environmentally sustainable manner.

Key Players

The wellhead equipment market is highly fragmented, with numerous players operating in the space. Some of the key players in the market include Schlumberger Limited, Halliburton Company, Baker Hughes Company, and Weatherford International. These companies offer a wide range of wellhead equipment, including valves, BOPs, and other related products. In addition, these companies are investing heavily in research and development to develop new technologies and equipment that can improve safety and efficiency in drilling operations.

Conclusion

The market for wellhead equipment in oil and gas drilling is rapidly evolving, with new technologies and equipment being introduced regularly. Valves and BOPs remain essential pieces of equipment for any wellhead system, but drilling companies are also investing in new technologies aimed at improving safety and efficiency. As demand for oil and gas continues to increase, the market for wellhead equipment is expected to experience significant growth in the coming years.

Wellhead pressure plays a critical role in guiding both the design and execution of hydraulic fracturing operations, as well as in selecting suitable wellhead equipment and pipeline configurations (Shen et al. ). High wellhead pressure can overload surface equipment, increasing the risk of pipe string rupture and equipment failure (Zheng et al. ). During staged fracturing of horizontal wells, excessive wellhead pressure may cause overextension of fractures or the formation of a single dominant fracture, limiting the development of complex fracture networks (Liu et al. ; Wang et al. a, b; Xie et al. ). In high-pressure formations, initiating fractures under pressure-limited but displacement-unlimited conditions can enhance fracture complexity and facilitate branch fracture formation (Pu et al. ; Zang et al. ). Furthermore, reducing wellhead pressure helps minimize reservoir damage and improves fracturing fluid flowback efficiency for subsequent operations (Yu et al. ; Zhang ). Consequently, the reduction of wellhead pressure is a central concern in hydraulic fracturing. Based on the fundamental principles of fracturing: Bottom-hole pressure equals the sum of wellhead pressure and hydrostatic column pressure minus frictional drag. It must also exceed the fracture pressure to initiate and propagate fractures, wellhead pressure can be reduced through three primary approaches: increasing hydrostatic column pressure, minimizing frictional resistance, and lowering fracture initiation pressure (Al-Mukhtar et al. ; Mnzool et al. ).

Hydraulic fracturing remains one of the most widely employed techniques for the exploration of sustainable energy resources (Peng et al. ). However, the presence x19operational efficiency (Guo et al. ). As fracturing fluid flows from the wellhead into the fracture, friction at each stage can result in pressure losses (Jia et al. ; Wang et al. a, b). Excessive frictional losses may lead to elevated wellhead pressure, which in turn increases the risk of safety hazards during fracturing operations (Ibrahim et al. ; ZhangNemcik ). Consequently, the extent of fracturing fluid friction directly influences the success of the fracturing process, as well as the ability to guide fractures effectively. Frictional pressure, therefore, is a critical parameter in the design and execution of hydraulic fracturing (Zhou et al. ).

Hydrostatic column pressure is primarily increased through the treatment of fracturing fluids. As advancements in exploration and drilling have extended the depth of oil and gas reservoir development, they have introduced significant challenges related to abnormally high pressure and ultra-high temperatures (Yang et al. a, b). In this context, weighted fracturing fluids have emerged as a key technology for addressing these issues using existing fracturing equipment (Yang et al. a, b). Among the various weighting methods, inorganic salt weighting remains the most commonly applied. Initially developed in , this technology has since undergone continuous refinement through extensive research, resulting in a comprehensive preparation methodology for weighted fracturing fluids (Almubarak et al. ; Mao et al. ; Yamak et al. ; Zhang et al. ; Zhao et al. a, b). The process begins with selecting an appropriate inorganic salt as the weighting agent, based on its density. Subsequently, fracturing fluid additives are chosen to achieve high-density, high-temperature-resistant formulations. The rheological properties of these fluids are then evaluated, including apparent viscosity under specific temperature and shear rate conditions, to ensure they meet the demanding requirements of high-temperature deep wells. Key parameters, such as suspended sand, residual content, friction, and permeability damage to the core matrix, are closely monitored to determine whether the desired fracturing performance is achieved (Yang et al. ; Zhao et al. ). If the formulation meets these criteria, the weighted fracturing fluid can be employed as a new working fluid in oil fields; otherwise, the formulation must be revised.

A common and significant challenge in unconventional reservoirs is the abnormally high breakdown pressure associated with reservoir tightness (Tariq et al. a, b). Hydraulic fracturing operations in such formations become increasingly difficult, often reaching the maximum pumping capacity without achieving sufficient fracturing (Tariq et al. a, b). Numerous studies have focused on reducing formation fracture pressure to address this issue. For instance, Li Hao developed a high-strength, pressure-resistant material and acid-resistant thickener, and conducted simulations using natural cores from the Changqing Oilfield in China. These simulations investigated crack initiation, propagation, and characteristics in conventional hydraulic fracturing, acid fluid fracturing, and thickener-compound acid fluid fracturing (Al-Mukhtar ; Al-MukhtarMerkel ; LiShi ; Majeed et al. ). Zeng Fanhui established a mathematical model to predict fracture pressure following acidizing treatments, validated through field data. The results indicated a reduction in fracture pressure due to decreased rock strength and fracture-critical stress intensity, primarily driven by acid-induced damage. Acid dissolution disrupted the crystal structure of mineral particles, weakened cementing materials, increased porosity, and ultimately lowered rock strength. Additionally, increasing caustic concentration, formation temperature, and acid treatment time further contributed to reducing fracture pressure within the wellbore. By applying this model, optimal acid treatment parameters were identified to effectively reduce fracture pressure (Fanhui et al. ). Consequently, reducing fracture pressure in unconventional tight reservoirs remains a critical area of research.

This paper focuses on three key aspects: (1) examining various methods to reduce friction along the string and near the wellbore, based on different friction types; (2) exploring techniques for reducing formation fracture pressure during hydraulic fracturing; and (3) investigating approaches to increase hydrostatic column pressure. Through a comprehensive analysis of these three aspects, the paper evaluates the effectiveness of different methods for reducing wellhead construction pressure. The advantages and limitations of each method are discussed, and recommendations are made regarding the prioritization of strategies for lowering wellhead pressure. These findings provide a theoretical basis for ensuring wellhead pressure safety during hydraulic fracturing operations. Figure 1 illustrates the conceptual framework and structure of this paper.

Frictional pressure loss in hydraulic fracturing can be categorized into two types (Massaras et al. ; Rueda et al. ; Wilson ). The first type is frictional resistance encountered by the fracturing fluid as it flows through the wellbore string, including the tubing, casing, or annulus. This friction loss is primarily caused by the interaction between the fracturing fluid and the wellbore walls. Generally, higher flow rates, smaller string diameters, greater fluid viscosity, and higher proppant concentrations result in increased friction along the string (Jeffrey et al. ; SuFong ); The second type is near-wellbore friction, which includes local friction as the fracturing fluid passes through perforation holes and bending friction in the near-wellbore zone. Factors such as insufficient perforation numbers, poor hole cleanliness, and blockages contribute to local friction resistance. Additionally, improper perforation orientation, poor cementing quality, and multiple competing fractures can lead to increased bending friction (Barree ; Li et al. ; Nicholson et al. ).

Analysis of methods for reducing friction along the string

Optimization of pipe string size

The optimization of pipe string size involves adjusting the diameter of the pipe string or combining different pipe string sizes to reduce friction along the pipeline. This method is based on calculating friction losses along the flow path. Lord and McGowen () introduced the concept of the drag reduction ratio to estimate friction in pipe strings (Lord ; NolteSmith ).

where, \( \Delta Pf \)(Pf)p refers to fracturing fluid friction, MPa; refers to Clearwater friction, MPa;\( \Delta Pf \) refers to drag reduction ratio coefficient.

According to Eq. 1, the friction of fracturing fluid is related to the friction of clean water and the drag reduction ratio coefficient. The drag reduction ratio coefficient is primarily determined using an empirical formula specific to the oilfield. Therefore, to calculate the friction of fracturing fluid, it is first necessary to measure the friction of clean water. This is done using the Bella-Hughes water friction formula from fluid mechanics (Lord ; NolteSmith ).

Where, △P1 refers to clear water friction, MPa; D refers to the inner diameter of the string, m; Q1 refers to construction displacement, m3/s; L refers to string length, m.

According to Eq. 2, the frictional resistance of fracturing fluid is primarily determined by the inner diameter of the pipe string, the construction displacement, and the length of the pipe string. In real-world oil field applications, the reservoir depth is generally fixed, making it impractical to reduce friction by altering the length of the pipe string.

To decrease frictional resistance along the pipe string, adjustments should focus on the inner diameter of the pipe string and the construction displacement. According to Eq. 2, frictional resistance can be reduced by increasing the inner diameter of the pipe string and decreasing the construction displacement. Given a constant drag reduction ratio, reducing the friction of clean water will correspondingly decrease the friction of the fracturing fluid. In conclusion, increasing the inner diameter of the pipe string and reducing the flow rate are effective strategies for minimizing frictional resistance along the pipe string.

Injection mode optimization

Fracturing fluid injection into the formation can be categorized into three methods based on the type of pipe string: tubing injection, casing injection, and a combination of tubing and casing injection. The friction and wellhead pressure generated by each of these injection methods differ depending on the specific approach employed.

The selection of an injection method is influenced by factors such as injection pressure, reservoir modification requirements, reservoir thickness, casing quality, and casing structure. Since this study primarily focuses on reducing wellhead pressure, injection pressure is particularly significant. Assuming all other conditions remain constant, higher injection speeds result in greater frictional resistance.

Tubing injection is no longer considered a reliable method for fracturing fluid injection due to the high friction resistance encountered in deep well sections. This results in excessive power consumption, low displacement rates, and increased pump pressure, all of which hinder effective fracturing. In contrast, casing injection is more effective at reducing friction, particularly at the deeper sections of the well. Currently, casing injection has been successfully implemented in various fracturing operations across numerous oil fields (Peralta et al. ; Shen et al. ).

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Tubing and casing injection technology has proven effective in reducing pipe string friction during large-scale sand fracturing operations. This method also increases bottom-hole pressure, thereby enhancing post-fracturing stimulation (Wiktorski et al. ).

Fracturing fluid formulation optimization

Additives in fracturing fluids significantly influence friction loss along the string. Therefore, it is crucial to optimize the formulation of fracturing fluids. This includes the careful selection of gelling agents (GomaaNasr-El-Din ; Liu ; Takahashi et al. )and cross-linking agents (Liang et al. ; Manas et al. ; Marshall et al. ). A summary of methods for reducing friction along the string through the optimization of fracturing fluid formulations is provided.

(1) Gelling agent and its concentration optimization.

As the additive of fracturing fluid in deep oilfield, it is necessary in order to reduce friction well on the premise of guaranteeing the performance of fracturing fluid(Hawkins ). If there is residue and water insoluble matter. It will cause the plugging of fracture pores after fracturing, which will influence the conductivity of fractures and reduce the stimulation ratio. If the selected gelling agent is not resistant to high temperatures and does not work stably in the formation, it will be unable to achieve the desired fracturing quality and final production (Powell et al. ).

Therefore, when selecting a gelling agent, it is essential to conduct temperature shear performance tests and residue content tests on several alternative thickeners (ChetanSongire ; Prakash et al. ). Based on the residue content results obtained from these tests, the appropriate concentration of the gelling agent should then be determined.

(2)Optimization of high temperature delayed crosslinking agent.

Achieving delayed crosslinking in fracturing fluids can effectively reduce the friction coefficient and construction friction. Currently, there are two established technologies for delayed crosslinking. The first involves adjusting the crosslinking time by varying the concentration of the crosslinking agent (Dai et al. ; Zhang et al. ). The second method delays crosslinking by altering the pH value (Bagal et al. ). Both temperature and pH value influence the crosslinking time of fracturing fluids, with crosslinking time generally increasing with pH and decreasing with temperature (Wei et al. ). Therefore, for specific high-temperature deep oil and gas fields, it is advisable to simulate the wellbore temperature conditions and adjust the pH value to determine the optimal delayed crosslinking time and thereby minimize friction along the string.

Chemical drag reducer

Incorporating chemical drag reducers into fracturing fluids can significantly reduce friction along the tubing (CampbellJovancicevic ). Polymers are the most commonly used drag-reducing agents in oil fields (Jing et al. ; Le Brun et al. ). These drag reducers effectively reduce string loss during fracturing and enhance wellhead pressure. The drag reduction mechanism of polymers is attributed to their chemical structure, including the length of the main chain molecules, their soft texture, and viscoelastic properties. These characteristics help suppress turbulent pulsations as the fracturing fluid flows through the system. Min proposed that polymer additives store the elastic energy from the flow very near the wall as shown in Fig. 2, in which when the relaxation time is long enough, this high elastic energy is transported to and dissipated into the buffer by near-wall vortical motion, resulting in significant drag reduction (Min et al. ). Consequently, the addition of polymers can lead to a significant reduction in the Rayleigh number, thereby achieving a substantial drag reduction effect (Xiong et al. ).

Drag reducers are generally separated into oil-soluble drag reducers and water-soluble drag reducers. Oil soluble drag reducing agents include polymethacrylate, olefin copolymer, poly long-chain a-olefin, polyisobutylene and so on; Water soluble drag reducing agents include polyacrylamide (PAM), synthetic polyethylene oxide (PEO), natural guanidine gum, amphora bean, saponin powder, Tianqing powder and so on. Table 1 shows the use of chemical drag reducers in recent years, as well as their strength. Table 2 shows four methods of reducing friction along the string and compares their characteristics.

Analysis method of near well bore friction

Near-wellbore friction, comprising local and bending friction, is a critical parameter in fracturing operations that cannot be overlooked (Jiang et al. ). Excessive near-wellbore friction necessitates higher pressure to fracture the formation and requires more powerful surface equipment, leading to increased operational costs and reduced economic profitability (Jaimes et al. ).To address the issue of excessive friction resulting from poor perforation quality, various methods have been implemented across fields to reduce near-wellbore friction (Alam et al. ; Hakim et al. ; Salazar et al. ; Yuan et al. ). The commonly employed methods include the following:

Widening artificial fracture

For non-Newtonian fluids, the artificial fracture width can be expressed as(Wang et al. a, b).

Where, refers to artificial crack width, m; μf refers to fracturing fluid viscosity, mPa·s; Kn refers to consistency coefficient of fracturing fluid, mPa·s; n refers to fracturing fluid flow coefficient; Q2 refers to pump displacement, m3/min; E refers to elastic modulus of rock, MPa; hf refers to hydraulic fracture height, m; refers to rock Poisson’s ratio (dimensionally); t∗ refers to time, m.

Formula 3 illustrates that increasing fracturing fluid viscosity and construction displacement results in wider simulated fractures. Consequently, a wider artificial fracture near the wellbore reduces the local friction experienced by the fracturing fluid. This method is theoretically well-established and straightforward to implement. Currently, high-viscosity friction reducers are employed in oilfields to transport proppant particles to sufficient depths (BiheriImqam ; BiheriImqam ; Ellafi et al. ; Phatak et al. ; Tomomewo et al. ).

Wang Tianyi utilized the finite element method (FEM) to simulate dynamic pressure depletion during reservoir production, focusing specifically on the relationship between fracture half-length and wellbore pressure. The simulation results are depicted in Fig. 3(a). Figure 3(b) illustrates the variation of average reservoir pressure with production time for various fracture half-lengths. These results indicate that wellbore pressure decreases as the fracture half-length increases.

Proppant scouring

Proppant scouring is a technique used to reduce near-wellbore friction (Nagar et al. ; Upchurch ). This method involves pulse sand injection and the use of high-speed sand-containing fracturing fluids. The process includes intense flushing and abrasion of perforated sections with poor perforation quality and rough, curved fractures near the wellbore. The technique aims to erode these problematic areas, thereby improving the permeability and smoothness of the fracturing fluid injection channels and, consequently, reducing frictional resistance near the well (McDaniel et al. ).

Field trials have demonstrated that proppant slug flushing, when used in conjunction with other technologies, can significantly enhance the success rates of fracturing operations (Cramer ). This method proves particularly effective in formations with imperfect pores, high fracture tortuosity, and substantial surface roughness (Vincent ). Consequently, proppant slug scouring technology has been increasingly adopted in oilfields to reduce near-wellbore friction (Al-Tailji et al. ; McDanielSurjaatmadja ; Wang et al. a, b; Zhang et al. ).

Directional hydraulic fracturing

Directional hydraulic fracturing can effectively address near-wellbore friction at greater distances from the wellbore. If proppant scouring proves insufficient for mitigating near-wellbore friction at extended distances, directional fracturing should be considered as an alternative solution.

Directional hydraulic fracturing aims to be achieved by perforating the main fracture, thereby preventing artificial fractures in the near-wellbore area from propagating through other micro-pores and forming a complex fracture network (Cheng et al. ; WeiyongChangchun )The formation of such complex fracture networks can lead to a significant increase in near-wellbore friction as fracturing fluids traverse these intricate fractures (Bai et al. ). The direction of directional hydraulic fracturing is influenced by the orientation of the main fracture, which is determined by the minimum and maximum horizontal principal stresses (Guo et al. ). Therefore, it is essential to establish the stress structure and fracture orientation of the reservoir before initiating directional hydraulic fracturing (Bai et al. ; ZhangZhang ). Once the magnitude and direction of reservoir stress are accurately determined, an optimized perforation plan based on formation conditions can be developed. This approach allows for the effective application of directional hydraulic fracturing to reduce near-wellbore friction (Klishin et al. ; LekontsevSazhin ; ZhangKang ). Figure 4 indicates the application of directional fracturing in laboratory and simulation. In this figure, experimental tests and discrete element method (DEM) numerical simulations using Particle Flow Code (PFC2D) were combined. This approach was used to investigate the initiation and propagation mechanisms of directional hydraulic fracturing controlled by dense linear multihole structures. The fracture geometry observed in the numerical simulations closely matched experimental results(ZhangZhang ). Table 3 summarizes several methods for reducing near-wellbore friction and provides a brief analysis of their suitability.

Hydrostatic column pressure during fracturing refers to the pressure exerted by the static weight of the fracturing fluid. According to the expression for hydrostatic column pressure (WangGe ):

Where, P refers to Hydrostatic column pressure, MPa; H refers to Well depth, m; g refers to gravitational acceleration, m/s2; \( \rho \) refers to fracturing fluid density, g/cm3;

Hydrostatic column pressure depends on gravitational acceleration, fracturing fluid density, and fluid height, but is independent of the wellbore size. For actual oil wells, the gravitational acceleration (g) and the fluid height (which is equal to the well depth) are fixed values. Therefore, to increase the hydrostatic pressure of the fracturing fluid, it is necessary to increase the fluid density.

Inorganic salt and compound inorganic salt aggravation

The traditional weighting method involves using inorganic salts as weighting agents for liquid weighting. Common examples include sodium bromide, sodium nitrate, calcium bromide, and potassium chloride. Additionally, there are various inorganic salt combinations used to enhance weighting, such as the sodium chloride-sodium nitrate complex and the sodium chloride-sodium bromide complex.

Currently, various weighting fracturing fluid systems utilizing inorganic salts as weighting agents have demonstrated effective applications in oil fields (Olson et al. ; Sierra ; Zhang et al. ). Liu Yi developed a weighted fracturing fluid with a high concentration of superglue guar gum, synthesized using a polymeric acid cross-linker. This fluid has a density of 1.365 g/cm³ and can withstand temperatures as high as 175 °C (Liu et al. ). Xiaojiang Yang modified guar gum to create a highly soluble super guar gum for use in a potassium formate (CHKO₂) weighted fracturing fluid system, employing a tertiary cross-linking strategy to address ultra-high reservoir temperatures. The density of fracturing fluid weighted by CHKO₂ reached up to 1.33 g/cm³, with an operational temperature limit of 180 °C. After fracturing, the fluid completely breaks down, leaving minimal residue. (Yang et al. a, b). Yongping Li introduced a nitrate-weighted fracturing fluid system designed to lower treatment pressure. This delayed cross-linked system offers high-temperature stability and shear resistance, with a density reaching 1.35 g/cm³ (Li et al. ). Jie Wang investigated an adjustable fracturing fluid system with high specific gravity and temperature resistance, tailored for deep, high-temperature reservoirs. The formula consists of 0.5 wt% polymer GX-100, 0.65 wt% cross-linker WQ-180, 2.5 wt% pH regulator, and KCl as the weighting agent. The results indicated excellent temperature and shear resistance, achieving a density of up to 1.30 g/cm³. This system addresses challenges in ultra-deep, high-temperature hydraulic stimulation and improves stimulation success rates (Wang et al. a, b). Peng Jianxin developed a non-acid chelating agent to enhance production and mitigate damage. Based on a chelation mechanism, this agent preferentially chelates divalent metal ions such as barium or calcium. The non-acid chelating agent, with a density of 1.03 g/cm³, demonstrates increased capacity to dissolve barium ions as concentration and temperature rise (Jianxin et al. ).

Organic salt aggravations

Inorganic salt weighting technology is a conventional method used in oil fields, but it presents two significant issues. First, the addition of inorganic salts often results in a substantial increase in the frictional resistance of the fracturing fluid. This increase can offset the benefits of the enhanced hydrostatic column pressure, rendering the weighting effect negligible. Second, the injection of inorganic salts can cause severe damage to the formation core pores, leading to reduced permeability. These problems significantly impact the effectiveness of fracturing fluids that use inorganic salts as weighting agents. Therefore, there is a need to improve traditional weighting technologies to address these challenges.

Inorganic salt weighting is tantamount to adding inorganic salt directly into the water. This way of increasing the hydrostatic column pressure itself needs to consume a lot of inorganic salt, so the cost remains prohibitive. Therefore, a different weighting agent should be found to replace the traditional inorganic salt weighting fracturing fluid. At present, some people have successfully used organic acid as a weighting agent of fracturing fluid. Zihan Liao investigated hydroxyproline guar (HPG)-based HFF (HPG-HFF) using potassium formate (PF) as a weighting agent with and without a hydroxy carboxylate acid as an additional dispersion stabilizer. The density of fracturing fluid weighted by potassium formate was up to 1.47 g/cm3. Figure 5 is a comparison of different densities of weighted fracturing fluids. Figure 5a shows a NaBr-weighted gel fracturing fluid characterized by delayed cross-linking and good temperature resistance. The gel fracturing fluid achieved densities up to 1.372 g/cm2. When the concentrations of both thickener and cross-linking agent reached 0.8 wt%, the fluid exhibited adequate temperature and shear resistance at 200 °C and 100 s–1 (Zhao et al. ). Figure 5b indicates the change over 24 h after the organic fracturing fluid is configured. The study establishes the potential application of formate-based weighting agents, highlighting the effects of hydrogen bonding in complex HFF. This bench top study provides a foundation for future research to understand the application of formate - FW - based weighting HPG-HFF in down hole high temperature conditions. Figure 6 summarizes various weighting agents and corresponding fracturing fluid densities after weighting. As shown in Fig. 5, weighting significantly increases the fracturing fluid density (1.3–1.5 g/cm2), effectively enhancing hydrostatic column pressure and reducing wellhead pressure.

Solid particle weighting

Solid particle weighting agents are incorporated into fracturing fluids by adding particulate weighting agents to the base fluid. Tailor-made nanoparticles with superior gelling and suspension properties, which can be dissolved by hydrocarbons or removed by hydrocarbon flow during production, play a crucial role in enhancing well productivity and, consequently, the ultimate hydrocarbon recovery from a field (Al-Muntasheri et al. ).

Currently, particulate agents have been employed as weighting agents in fracturing processes. German and Juan D present experimental research on incorporating particulate agents into a commercial fracturing fluid commonly used for tight gas-condensate reservoirs. Rheological tests of different nanoparticles (100 and 200 mg/L) were conducted at 1.38 MPa and 104 °C. Improvements in fluid properties allowed modification of the original formulation, reducing methanol usage by up to 33% and formation damage by approximately 71% (Guzman et al. ). Wu Hairong proposed a SiO2 nanoparticle-assisted VES (viscoelastic surfactant) fracturing fluid with low concentration. The NAVES system (VES fracturing fluid), containing 1% EDAA and 0.01% SiO₂, maintains a shear viscosity above 33 mPa·s at 70 °C for 2 h (Wu et al. ). Zhou Ming prepared two types of clean fracturing fluids: VES-W without nano-TiO2 and VES-N with nano-TiO2, utilizing a cationic trimer surfactant as the main agent. After adding nano-TiO₂, the VES-N system exhibited higher strength compared to the VES-W system, with temperature resistances of 100 °C and 81 °C, respectively. The nano-TiO₂ particles significantly enhanced the viscoelasticity of the VES-N fluid. Additionally, the lower proppant settling rate in VES-N indicates improved sand-carrying capacity due to nano-TiO₂ addition (Zhou et al. ). Lv Qichao investigated a foam stabilized by partially hydrophobic modified SiO2 and sodium dodecyl benzenesulfonate (SDBS) as a fracturing fluid. Experimental data indicated that adding silica (SiO₂) nanoparticles enhanced the stability and thermal adaptability of sodium dodecyl benzenesulfonate (SDBS) foam, while the surface tension of the SDBS dispersion remained virtually unchanged. (Lv et al. ). Figure 7 illustrates the mechanism by which nanoparticles enhance the rheological properties of a VES fracturing fluid, exemplified by the interaction of cationic surfactant cetyltrimethylammonium bromide (CTAB) wormlike micelles with anionic silica nanoparticles (NPs). The improvement arises from micellar end-caps binding to NP surfaces, promoting micelle elongation or cross-linking (Shibaev et al. ). Table 4 summarizes various fracturing fluid weighting methods and compares their advantages and disadvantages.

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