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Flow Characteristics of Dual-Increasing Stimulation Slurry in Unconsolidated Silty Sandstone
LIU Xilong, SUN Qian, ZHANG Guobiao, LI Bing, ZHANG Kewei
, Available online  
Abstract(59) HTML (30) PDF (7827KB)(3)
Abstract:
The dual-increasing stimulation slurry is a novel stimulation fluid developed for weakly cemented reservoirs, such as submarine methane-hydrate-bearing silty sandstones. After injection into the formation, it consolidates to form porous-media slurry veins that enhance permeability. This study employed a slurry fracture flow visualization apparatus to investigate the flow characteristics of the slurry within muddy silty sediments. The experiments revealed the influence of geological parameters, slurry formulation, and operational parameters on slurry flow, fluid loss, and slurry-vein porosity. The results indicate that the slurry flows uniformly and exhibits a convex fracture flow profile, flowing to the end of main fracture and branch fracture, effectively filling fractures. Lower fluid loss increases the proportion of medium-to-large pores within the slurry veins. Adjusting the slurry formulation can reduce fluid loss in formations of varying permeability, whereas a high injection rate expands the fluid loss zone. The effective porosity ranges from 50% to 60% with a uniformly distributed pore space, forming a structure dominated by large pores (pore diameter > 50 nm) and densely distributed micro- to mesopores (pore diameter < 50 nm). This pore network can serve as high-conductivity channels for gas and water migration, while the dense distribution of small and medium pores is conducive to sand control.
A New High-temperature Tackifier for Solid-free Drilling Fluids
ZHOU Guowei, ZHANG Xin, YAN Weijun, HUA Guiyou, ZHUANG Zhenhua, QIU Zhengsong
, Available online  
Abstract(60) HTML (46) PDF (2972KB)(2)
Abstract:
The Ordovician buried-hill reservoir in Liaohe Oilfield exhibits a challenging high-temperature (200℃ at reservoir center) and low-pressure (pressure coefficient 1.01～1.06) environment characteristic of typical high-temperature, low-pressure oil/gas reservoirs. To achieve formation protection, a solids-free water based drilling fluid was prioritized, with tackifier selection being critical. Through molecular structure optimization, a novel high-temperature/salt-resistant tackifier was developed using four monomers: N-vinylpyrrolidone (NVP), 2-acrylamido-2-methylpropane sulfonic acid (AMPS), N'N-diethylacrylamide (DEAA), and 1-(3-sulfopropyl)-2-vinylpyridinium hydroxide inner salt. The synthesis employed N'N-methylene bisacrylamide as crosslinker with potassium persulfate and sodium bisulfite as redox initiators. FTIR and TGA analysis confirmed successful polymerization, demonstrating superior thermal stability with 296.66℃ initial decomposition temperature and only 45.96% mass loss during degradation phase, outperforming commercial HE300. The fluid achieved remarkable rheological performance with 722 consistency coefficient (K) at 0.5% concentration. Laboratory evaluations verified exceptional thermal stability up to 220℃ and saturated salt tolerance. Field applications demonstrated excellent viscosity-enhancing performance and robust durability of this novel tackifier, providing vital technical support for buried-hill reservoir development and high-temperature formation drilling operations.
Anti-ultra-high Temperature Suspension Stabilizer HPAS for Oil-based Drilling and Completion Fluid and Its Mechanism of Action
KOU Yahao, NI Xiaoxiao, WANG Jianhua, ZHANG Jiaqi, YIN Da, CHI Jun
, Available online  
Abstract(67) HTML (34) PDF (4286KB)(6)
Abstract:
Aiming at the problem that the suspension stability of oil-based drilling and completion fluid was difficult to maintain at high temperature above 240℃, based on the principle of enhancing colloidal stability by space grid structure, a strong hydrophobic suspension stabilizer HPAS was developed by using sepiolite fiber and n-octyltriethoxysilane as raw materials and organic modification after hydrochloric acid treatment. The monomer was characterized by infrared spectroscopy, thermogravimetric analysis, particle size analysis and surface wettability, which proved that the modification was successful. A set of high density oil base drilling fluid based on HPAS had good performance after aging at 260℃, its AV and PV were maintained at about 33 mPa·s and 27 mPa·s, the dynamic shear force was maintained above 4 Pa, ES was higher than 800 V, the FLHTHP was controlled below 5 mL, and the mud cake thickness was less than 2 mm. Through the settlement stability evaluation, it was found that there was no hard sink at 240℃ for 7 days, and the open tank state was that the glass rod fell freely and touched the bottom easily, which met the requirements of field application. In addition, the system maintained YP above 4.5 Pa in the temperature and pressure range of 65-240℃ and normal pressure −190 MPa, which ensured the good suspension stability and cuttings carrying capacity of the system. It provided technical support for the further application of oil-based drilling and completion fluid in deep wells, ultra-deep wells and 10,000 meters deep wells.
Formulation Design of Drilling Fluid Loss Control and Plugging Strategies in Deepwater Subsalt Reservoirs
Xu Chengyuan, Zhong Jiangcheng, Zhu Haifeng, Xiang Ming, Lin Zhiqiang, Yang Jie, Chen Jiaxu
, Available online  
Abstract(145) HTML (113) PDF (5300KB)(8)
Abstract:
Subsalt oil and gas resources are abundant worldwide, with significant reserves located in the deepwater offshore regions of Brazil. The Mero field is a typical example of deepwater subsalt oil and gas resources, located in the southeastern Santos Basin offshore Brazil. The reservoir depth exceeds 5000 meters, with an overlying salt gypsum layer ranging from 150 to 3000 meters. The subsalt reservoirs are primarily composed of Lower Cretaceous BVE and ITP carbonate rocks. The Mero3 block in the Mero field experiences the most severe lost circulation, with a total loss of 17,105 m3. Through geological and drilling data analysis, the main causes of lost circulation were identified, including the development of faults and natural fractures, weak formation layers, and the strong heterogeneity of the formation. These factors collectively result in poor pressure-bearing capacity of the sealing layer, leading to repeated lost circulation incidents. This study collected commonly used plugging materials in the Mero field and conducted performance evaluation experiments on particle size distribution, friction coefficient, compressive strength, and compatibility. A database of plugging material performance parameters was established, and high-performance plugging materials suitable for deepwater subsalt reservoir loss prevention and plugging operations were selected. Based on different loss rates, three loss prevention formulas were designed using efficient bridging and dense filling methods, and the application process for these formulas was refined. Furthermore, a strategy for fine-tuning drilling techniques and maintaining a combination of loss prevention and plugging was proposed. This strategy includes strengthening the precise control of the wellbore ECD in loss-prone formations, reducing downhole overpressure, and minimizing the occurrence of induced fractures. The research results achieved significant success in the field plugging operations at the NW8 well of the Mero3 block. In cases with varying loss rates, the plugging strategy effectively slowed down the loss rate. This provides valuable technical support for the oil and gas development of Brazil's Mero field and other similar subsalt reservoirs, promoting the safe and efficient extraction of oil and gas resources.

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