A novel formulation of an eco-friendly calcium nitrate-based heavy completion fluid.

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 CN4, CNG14, CNG24, and CNG34 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 CNG24 becomes cloudy at 285 °F, and the fluid CNG34 becomes cloudy from 212 °F onward, but the CN4 fluid remains clear and transparent at all temperatures. In the tested high temperatures, the effect on their pH was around the same. The fluids CN4, CNG24, and CNG34 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 CNG24, which contained calcium nitrate and G2 alcohol. This fluid had the best overall performance and safety of the fluids tested.

A comparative study of brine solutions as completion fluids for oil and gas fields.

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.

Sandstone chemical consolidation and wettability improvement using furan polymer-based nanofluid.

The oil and gas industry faces a challenge in meeting global energy demand due to sand production in unconsolidated or semi-consolidated reservoirs, leading to equipment wear, production instability, and significant financial burdens. Mechanical and chemical sand control methods are being used among which chemical sand consolidation techniques have emerged as a promising solution. In this research, furan polymer-based nanofluid is investigated as a chemical consolidant to explore its intriguing properties and characteristics and how the quantity of nanoparticles influences the fundamental properties of curing resin and wettability while pioneering a groundbreaking approach to enhancing regaining permeability. According to the findings, a substantial boost in core compressive strength has been achieved as well as an impressive increase in re-permeability, especially for the foam injection case, by the meticulous optimization of nanofluid composition. The results include a remarkable regain permeability of 91.37%, a robust compressive strength of 1812.05 psi, and a noteworthy 15.32-degree shift towards water-wet wettability. Furthermore, silica nanoparticles were incorporated to enhance the thermal stability of the fluid, rendering it more adaptable to higher temperatures. Therefore, Furan polymer-based nanofluid is not only expected to present a solution to the challenge of sand production in the oil and gas industry but also to provide operational sustainability.

Optimization of salinity and composition of injected low salinity water into sandstone reservoirs with minimum scale deposition.

In this study, a mechanistic and comprehensive examination of the impact of the scale formation situation of different diluted seawater levels was conducted to investigate the influence of important factors on the performance and efficiency of low salinity water. To clarify the effective participating mechanisms, scale precipitation by compatibility test, field emission scanning electron microscopy (FESEM) and energy dispersive X-ray spectroscopy (EDX) analysis, zeta potentials as surface charge, ion concentration changes, contact angle, pH, CO2 concentration, electrical conductivity, and ionic strength were analyzed. The results showed that increasing the dilution time to the optimal level (10 times-diluted seawater (SW#10D)) could effectively reduce the amount of severe precipitation of calcium carbonate (CaCO3) and calcium sulfate (CaSO4) scales. However, the reduction in CaCO3 scale precipitation (due to mixing different time diluted seawater with formation brine) and its effect on the wettability alteration (due to the change in surface charge of OLSW/oil and sandstone/OLSW) had higher impacts. The zeta potential results have shown that OLSW with optimum salinity, dilution, and ionic composition compared to different low salinity water compositions could change the surface charge of OLSW/oil/rock (- 16.7 mV) and OLSW/rock (- 10.5 mV) interfaces toward an extra negatively charged. FESEM and contact angle findings confirmed zeta potential results, i.e. OLSW was able to make sandstone surface more negative with diluting seawater and wettability changes from oil-wet toward water-wet. As a result, SW#10D was characterized by minimum scaling tendency and scale deposition (60 mg/l), maximum surface charge of OLSW/oil/rock (- 16.7 mV), and the potential of incremental oil recovery due to wettability alteration toward more water-wetness (the oil/rock contact angle ~ 50.13°) compared with other diluted seawater levels.

Optimizing acidizing design and effectiveness assessment with machine learning for predicting post-acidizing permeability.

Formation damage poses a widespread challenge in the oil and gas industry, leading to diminished permeability, flow rates, and overall well productivity. Acidizing is a commonly employed technique aimed at mitigating damage and enhancing permeability. In this study, to predict the permeability after acidizing in oil and gas reservoirs, three machine learning models, namely artificial neural networks, random forest, and XGBoost, along with genetic programming were used to estimate permeability changes after acidizing. These models are utilized to estimate permeability changes following acidizing operations. Training of the models involved a dataset comprising 218 acidizing operations conducted in diverse reservoirs across Iran. The input parameters, namely permeability, porosity, skin factor, calcite mineral fraction, acid injection rate, and injected acid volume, were optimized through the use of a genetic algorithm. Statistical and graphical analysis of the results demonstrates that genetic programming outperformed the other machine learning techniques, yielding superior performance with R square and RMSE values of 0.82 and 17.65, respectively. Nevertheless, the other models also exhibited commendable performance, surpassing an R square value of 0.73. The post-acidizing permeability data obtained from core flooding experiments conducted on carbonate and sandstone cores was utilized to validate the models. The genetic programming model demonstrates an average error of 21.1%. The evaluation of post-acidizing permeability using genetic programming, in comparison with the results obtained from the core-flood test, revealed errors of 22.95% and 32.4% for carbonate and sandstone cores, respectively. Furthermore, a comparison between the calculated post-acidizing permeability derived from the GP model and previous studies indicated errors within the range of 8.6-26.59%. The findings highlight the potential of genetic programming and machine learning algorithms in accurately predicting post-acidizing permeability, thereby aiding in acidizing design, effectiveness assessment, and ultimately enhancing oil and gas production rates.

Experimental Investigation on the Impacts of Fracture Roughness and Fluid Composition on the Formation of Bubble Bridges through the Microbubble Fluid Flow.

The colloidal gas Aphron (CGA) drilling fluids are an alternative to ordinary drilling mud to minimize formation damage by blocking rock pores with microbubbles in low-pressure or depleted reservoirs. Fractured formations usually have different characteristics and behavior in contrast to conventional ones and need to be investigated for Aphron applications. In this research, a series of core flood tests were conducted to understand the factors controlling the pore-blocking mechanisms of microbubbles in fractured formations. For the first time, a synthetic metal plug was used to simulate the fracture walls and eliminate the formation matrix effect. This study analyzed the effects of three fluid compositions, considering the polymer and surfactant concentrations at reservoir conditions, including temperature and overburden pressure. Additionally, fracture surface roughness as one of the parameters affecting the microbubble fluid penetration through the fracture path and bubble blockage were studied. The results indicated that microbubble fluid composition would not affect the bubble size or blockage probability. The different stable microbubble fluids resulted in the same pattern and conditions. Besides, fluid penetration would be more challenging if the fracture roughness decreased. Due to the accumulation of bubbles and the fact that some of them were trapped in the fracture's rough surface, the blockage possibility increased. According to the range of roughness for the steel core in previous studies and compared with the roughness of carbonate reservoir rocks, the roughness of fractured reservoir rocks is much higher than that of the steel surface. Accordingly, the observed trend in the experiments showed that when it is possible to form a bubble bridge in steel cores, then in carbonate rocks, we will definitely see blockage with any roughness, provided that other parameters are acceptable.

Comprehensive experimental investigation of the effective parameters on stability of silica nanoparticles during low salinity water flooding with minimum scale deposition into sandstone reservoirs.

Recent studies showed the high potential of nanofluids as an enhanced oil recovery (EOR) agent in oil reservoirs. This study aimed to investigate the effects of salts and ions, the salinity of aqueous solution, total dissolved solids (TDS), scale deposition of mixing brines, surface charge as zeta potential (ZP) value, and pH of injected brines as low salinity water (LSW) on the stability of silica nanoparticles (NPs). The experiments were conducted on the stability of silica NPs at different concentrations and brines to determine optimum salinity, dilution, cations, and anions concentrations. The results showed that 10 times diluted seawater (SW#10D) was optimum low salinity water (OLSW) as injected LSW and water-based nanofluids. Results showed that by decreasing the salinity, increasing seawater dilution, and removing Mg2+ and Ca2+ cations, the amount of scale deposition decreased, and the brine's brine's brine stability of NPs in brine improved. At the optimum salinity and dilution conditions, compared with other salinities, there was less scale formation with more nanofluid stability. Obtained results from ZP measurements and dynamic light scattering (DLS) showed that by removing divalent ions (Mg2+ and Ca2+) of water-based nanofluid (low salinity hard water (LSHW) composition), more NPs were attached to the surface due to the reduction in repulsive forces between the NPs. Therefore, at optimum low salinity soft water (OLSSW), more wettability alteration occurred compared with optimum low salinity hard water (OLSHW) due to the more stability of NPs in OLSSW. The obtained results from the contact angle measurements, surface adsorption of the NPs by FESEM images, and ZP measurements showed that the predominant mechanism in enhancing oil recovery by nanofluid was the wettability alteration by disjoining pressure. According to wettability alteration results, the silica NPs with an optimized concentration in the optimized LSHW and LSSW compositions could be improved the wettability alteration by up to 23.37% and 55.81% compared with the without NPs. The optimized LSSW compared with LSHW composition could be improved the wettability alteration by up to 11.69%. In addition, OLSSW-based nanofluid compared with OLSHW could be increased wettability alteration toward strongly water-wet by up to 33.44%.

Mechanistic Study of Micro-bubble Fluid Infiltration through the Fractured Medium.

Drilling in depleted reservoirs has many challenges due to the overbalance pressure. Another trouble associated with overbalance drilling is differential sticking and formation damage. Low-density drilling fluid is an advanced method for drilling these depleted reservoirs and pay zones with different pressures to balance the formation pore pressure and hydrostatic drilling fluid pressure. This study investigated the infiltration of a micro-bubble fluid as an underbalanced drilling method in fractured reservoirs. A novel method has been presented for drilling permeable formations and depleted reservoirs, leading to an impressive reduction in costs, high-tech facilities, and drilling mud invasion. It also reduces mud loss, formation damages, and skin effects during the drilling operation. This paper studied micro-bubble fluid infiltration in a single fracture, and a synthetic metal plug investigated the bridging phenomenon through the fractured medium. Moreover, the effects of fracture size, bubble size, and a pressure differential of fracture ends have been thoroughly analyzed, considering the polymer and surfactant concentrations at reservoir conditions, including the temperature and overburden pressure. In this study, nine experimental tests were designed using the design of experiment, Taguchi method. The results indicated that higher micro-bubble fluid mixing speed values make smaller bubbles with lower blocking ability in fracture (decrease the chance of blocking more than two times). On the other hand, a smaller fracture width increases the probability of bubble bridges in the fracture but is not as crucial as bubble size. As a result, drilling fluid infiltration in fractures and formation damages decreases in the condition of overbalanced drilling pressure differences of about 200 psi.

Optimization and treatment of wastewater of crude oil desalting unit and prediction of scale formation.

In this article, one of Iran's southwest oil fields that produces 3200 barrels per day (bbl/d) of wastewater from oil and gas processing was investigated. Experimental analysis of oil reservoir water and desalting wastewater disposal of crude oil desalting unit was performed. First, water was treated with a reverse osmosis membrane. As a result, the purified water, with lower total dissolved solids (TDS) and pH, was a suitable candidate for injection into the adjacent wells of the crude oil desalting unit. The effectiveness and compatibility of this wastewater to the formation water of the oil field wells were simulated. Finally, we studied and identified the formation, the amount, and the type of mineral scale deposits. These are the most important problems during water injection into the wells. The analysis shows that the refined water from the reverse osmosis (RO) process was a suitable and low-cost economical option for injection in onshore and offshore fields, due to the low amount of salts, the concentration of susceptible ions in scaling formation, and the appropriate pH. This oil field, which is in the second half of life, requires enhanced oil recovery methods (EOR) for the maintenance of pressure and an increase in oil recovery.