The Evaluation and Introduction of Novel Acid-Based Crosslinked Gel for HPHT Acid Fracturing Applications in Carbonate Formations

2022 ◽  
Author(s):  
Khalid Fahad Almulhem ◽  
Ataur Malik ◽  
Mustafa Ghazwi
Keyword(s):  
Traditional Approach ◽  
Reaction Rates ◽  
Field Trials ◽  
Gas Production ◽  
Carbonate Reservoir ◽  
Fluid System ◽  
Acid Fracturing ◽  
Acid Reaction ◽  
Carbonate Formations

Abstract Acid Fracturing has been one of the most effective stimulation technique applied in the carbonate formations to enhance oil and gas production. The traditional approach to stimulate the carbonate reservoir has been to pump crosslinked gel and acid blends such as plain 28% HCL, emulsified acid (EA) and in-situ gelled acid at fracture rates in order to maximize stimulated reservoir volume with desired conductivity. With the common challenges encountered in fracturing carbonate formations, including high leak-off and fast acid reaction rates, the conventional practice of acid fracturing involves complex pumping schemes of pad, acid and viscous diverter fluid cycles to achieve fracture length and conductivity targets. A new generation of Acid-Based Crosslinked (ABC) fluid system has been deployed to stimulate high temperature carbonate formations in three separate field trials aiming to provide rock-breaking viscosity, acid retardation and effective leak-off control. The ABC fluid system has been progressively introduced, initially starting as diverter / leak off control cycles of pad and acid stages. Later it was used as main acid-based fluid system for enhancing live acid penetration, diverting and reducing leakoff as well as keeping the rock open during hydraulic fracturing operation. Unlike in-situ crosslinked acid based system that uses acid reaction by products to start crosslinking process, the ABC fluid system uses a unique crosslinker/breaker combination independent of acid reaction. The system is prepared with 20% hydrochloric acid and an acrylamide polymer along with zirconium metal for delayed crosslinking in unspent acid. The ABC fluid system is aimed to reduced three fluid requirements to one by eliminating the need for an intricate pumping schedule that otherwise would include: a non-acid fracturing pad stage to breakdown the formation and generate the targeted fracture geometry; a retarded emulsified acid system to achieve deep penetrating, differently etched fractures, and a self-diverting agent to minimize fluid leak-off. This paper describes all efforts behind the introduction of this novel Acid-Based Crossliked fluid system in different field trials. Details of the fluid design optimization are included to illustrate how a single system can replace the need for multiple fluids. The ABC fluid was formulated to meet challenging bottom-hole formation conditions that resulted in encouraging post treatment well performance.

Using Advance Acid Fracturing Design to Increase the Production Efficiency in a HPHT Reservoir: A Success Story from Southern Mexico

2021 ◽  
Author(s):  
Frank Figueroa ◽  
Gustavo Mejías ◽  
José Frías ◽  
Bonifacio Brito ◽  
Diana Velázquez ◽  
...  
Keyword(s):  
High Temperature ◽  
Laboratory Tests ◽  
Reaction Rates ◽  
Gas Production ◽  
Carbonate Reservoir ◽  
Fluid Distribution ◽  
Acid Etching ◽  
Southern Mexico ◽  
Acid Fracturing ◽  
Fluid Systems

Abstract Enhanced hydrocarbon production in a high-pressure/high-temperature (HP/HT) carbonate reservoir, involves generating highly conductive channels using efficient diversion techniques and custom-designed acid-based fluid systems. Advanced stimulation design includes injection of different reactive fluids, which involves challenges associated with controlling fluid leak-off, implementing optimal diversion techniques, controlling acid reaction rates to withstand high-temperature conditions, and designing appropriate pumping schedules to increase well productivity and sustainability of its production through efficient acid etching and uniform fluid distribution in the pay zone. Laboratory tests such as rock mineralogy, acid etching on core samples and solubility tests on formation cuttings were performed to confirm rock dissolving capability, and to identify stimulation fluids that could generate optimal fracture lengths and maximus etching in the zone of interest while corrosion test was run to ensure corrosion control at HT conditions. After analyzing laboratory tests results, acid fluid systems were selected together with a self-crosslinking acid system for its diversion properties. In addition, customized pumping schedule was constructed using acid fracturing and diverting simulators and based on optimal conductivity/productivity results fluid stages number and sequence, flow rates and acid volumes were selected. The engineered acid treatment generated a network of conductive fractures that resulted in a significant improvement over initial production rate. Diverting agent efficiency was observed during pumping treatment by a 1,300 psi increase in surface pressures when the diverting agent entered the formation. Oil production increased from 648.7 to 3105.89 BPD, and gas production increased from 4.9 to 26.92 MMSCFD. This success results demonstrates that engineering design coupled with laboratory tailor fluids designs, integrated with a flawless execution, are the key to a successful stimulation. This paper describes the details of acidizing technique, treatment design and lessons learned during execution and results.

An Efficient Multiscale Method for the Simulation of In-situ Conversion Processes

SPE Journal ◽  
2015 ◽  
Vol 20 (03) ◽  
pp. 579-593 ◽  
Author(s):  
Hangyu Li ◽  
Jeroen C. Vink ◽  
Faruk O. Alpak
Keyword(s):  
Numerical Modeling ◽  
Reaction Rates ◽  
Sensitivity Study ◽  
Gas Production ◽  
Multiscale Method ◽  
Fine Scale ◽  
Computational Performance ◽  
Simulation Results ◽  
Coarse Grids

Summary Numerical modeling of the in-situ conversion process (ICP) is a challenging endeavor involving thermal multiphase flow, compositional pressure/volume/temperature (PVT) behavior, and chemical reactions that convert solid kerogen into light hydrocarbons, which are tightly coupled to temperature propagation. Our investigations of grid-resolution effects on the accuracy and performance of ICP simulations have demonstrated that ICP-simulation outcomes—specifically, chemical-reaction rates, kerogen-accumulation profiles, and oil-/gas-production rates, may exhibit relatively large errors on coarse grids. Coarse grids are attractive because they deliver favorable computational performance. We have developed a novel multiscale modeling method for simulating ICP that reduces numerical-modeling errors and reproduces fine-scale-simulation results on relatively coarse grids. The method uses a two-scale solution method, in which the reaction kinetics of the solids is solved locally on a fine-scale grid, with interpolated temperatures obtained from coarse-grid simulations of thermal flow and fluid transport. We demonstrate the accuracy and efficiency of our multiscale method with representative 1D models. It is shown that the method delivers accurate solutions for key ICP performance indicators with very little computational overhead compared with corresponding coarse-scale models. The robustness of the multiscale method has been verified over a number of physical-parameter ranges with a limited-scope sensitivity study. Numerical results show that the multiscale method consistently improves the simulation results and matches the fine-scale reference results closely.

Acid Fracturing Experience In Naturally Fractured – Heavy Oil Reservoir, Bati Raman Field

2021 ◽  
Author(s):  
Mustafa Erkin Gozel ◽  
Serkan Uysal ◽  
Cosan Ayan ◽  
Ugur Yuce ◽  
Egemen Ozturk ◽  
...  
Keyword(s):  
Heavy Oil ◽  
Laboratory Tests ◽  
Reaction Rates ◽  
Carbonate Reservoir ◽  
Production Performance ◽  
Total Production ◽  
Acid Fracturing ◽  
Wide Range ◽  
Fracture Closure ◽  
Naturally Fractured

Abstract Bati Raman field, with an original oil in place of 1.85 billion barrels, is a naturally fractured carbonate reservoir containing 9-13 °API extra heavy oil with viscosities varying from 300 to 600 cp. Not only a wide range of pilot EOR schemes including gas, thermal and chemical methods, but also novel IOR applications have been tried in the field. CO2 injection was a game changer for this reservoir which has been the main drive mechanism since 1987. Since then, various techniques are applied to further improve the production performance of the field. This study focuses on the design and outcome of the pilot acid fracturing treatments in selected three wells in the tighter and less fractured southeastern part of the reservoir. State of the art planning included full evaluation of well integrity, cement bond and open hole logs, geomechanics studies augmented with rock mechanics laboratory tests. Laboratory tests were also conducted focusing on sludge/emulsion forming tendencies and acid reaction rates. Using these results, expected fracture dimensions were predicted along with production forecasts. In all wells, pre-frac calibration tests were conducted to assess stress conditions and fracturing parameter optimization. The treatments were then executed, improving the procedure between each well for acid fracturing. Injections schemes were operationally efficient and various diversion techniques were used to mitigate the presence of naturally fractured zones. Pre and post-job temperature logs helped to evaluate each treatment. The results from the wells were very positive; total production rate increased about fivefold, observed within one month after the treatments. No considerable change in water or CO2 production in the wells was observed which had been one of the most important objectives during the candidate selection process. One well was suspended, which turned out to be one of the producers of the field after acid fracturing treatment. Each well had a different post-frac production performance because of its geological characteristics and flow dynamics, making the study more valuable for better understanding of the process. The wells are still on critical observation to assess the nature of the created fractures and their longevity in the long run. Even after twelve to fifteen months of production, which is the breaking point period for fracture closure, the overall production level of the wells was double compared to pre-frac rates. One well still has a fracture dominated production while other two changed back into its pre-frac rates. Based on these results, acid fracturing campaign was extended in the area which is currently under evaluation.

Anomalous Acid Reaction Rates in Carbonate Reservoir Rocks

SPE Journal ◽  
2006 ◽  
Vol 11 (04) ◽  
pp. 488-496 ◽  
Author(s):  
Kevin C. Taylor ◽  
Hisham A. Nasr-El-Din ◽  
Sudhir Mehta
Keyword(s):  
Saudi Arabia ◽  
Rotating Disk ◽  
Reaction Rates ◽  
Carbonate Reservoir ◽  
Reservoir Rock ◽  
Acid Dissolution ◽  
Gas Reservoir ◽  
Dissolution Rates ◽  
Reservoir Rocks ◽  
Acid Reaction

Summary It is generally assumed that the reaction of acid with limestone reservoir rock is much more rapid than acid reaction with dolomite reservoir rock. This work is the first to show this assumption to be false in some cases, because of mineral impurities commonly found in these rocks. Trace amounts of clay impurities in limestone reservoir rocks were found to reduce the acid dissolution rate by up to a factor of 25, to make the acid reactivity of these rocks similar to that of fully dolomitized rock. A rotating disk instrument was used to measure dissolution rates of reservoir rock from a deep, dolomitic gas reservoir in Saudi Arabia (275°F, 7,500 psi). More than 60 experiments were made at temperatures of 23 and 85°C and HCl concentration of 1.0 M (3.6 wt%). Eight distinctly different rock types that varied in composition from 0 to 100% dolomite were used in this study. In addition, the mineralogy of each rock disk was examined before and after each rotating disk experiment with an environmental scanning electron microscope (ESEM) using secondary and backscattered electron imaging and energy dispersive X-ray (EDS) spectroscopy. Acid reactivity was correlated with the detailed mineralogy of the reservoir rock. It was also shown that bulk anhydrite in the rock samples was converted to anhydrite fines by the acid at 85°C, a potential source of formation damage. Introduction A study of acid reaction rates and reaction coefficients of a dolomitic reservoir rock was recently reported by Taylor et al. (2004a). In that work, it was found that reaction rates depended on mineralogy and the presence of trace components such as clays. This paper examines in detail the relationship between acid reactivity and mineralogy of a deep, dolomitic gas reservoir rock. An accurate knowledge of acid reaction rates of deep gas reservoirs can contribute to the success of matrix and acid fracture treatments. Many studies of acid stimulation treatments of Formation K, a deep, dolomitic gas reservoir in Saudi Arabia, have been published (Nasr-El-Din et al. 2001, 2002a, 2002b; Bartko et al. 2003). It is generally assumed that the reaction of acid with limestone reservoir rock is much more rapid than acid reaction with dolomite reservoir rock during acidizing treatments. However, much of the reported data were obtained with pure limestones, dolomites, and marbles. These include calcite marble (CaCO3) (Lund et al. 1975; de Rozieres 1994; Frenier and Hill 2002), dolomite marble [CaMg(CO3)2] (Lund et al. 1973; Herman and White 1985), Indiana limestone (Mumallah 1991), St. Maximin and Lavoux limestones (Alkattan et al. 1998), Haute Vallée de l'Aude dolomite (Gautelier et al. 1999), Bellefonte dolomite (Herman and White 1985), San Andres dolomite (Anderson 1991), Kasota dolomite (Anderson 1991), and Khuff dolomite reservoir cores (Nasr-El-Din et al. 2002b). The effects of common acid additives on calcite and dolomite dissolution rates were reported in detail (Frenier and Hill 2002; Taylor et al. (2004b; Al-Mohammed et al. 2006). The effects of impurities such as clays on rock dissolution have not been reported.

A New Acid Fracturing Fluid System for High Temperature Deep Well Carbonate Reservoir

2016 ◽  
Author(s):  
Ying Gao ◽  
Shengjiang Lian ◽  
Yang Shi ◽  
Xianyou Yang ◽  
Fujian Zhou ◽  
...  
Keyword(s):  
High Temperature ◽  
Carbonate Reservoir ◽  
Fracturing Fluid ◽  
Fluid System ◽  
Acid Fracturing ◽  
Deep Well

Integrated Subsurface to Surface Modeling to Assess Reservoir Uncertainty Quantification to A Carbonate Reservoir

2020 ◽  
Author(s):  
A. Chaterine
Keyword(s):  
Uncertainty Quantification ◽  
Gas Production ◽  
Carbonate Reservoir ◽  
Production Volume ◽  
Production Forecast ◽  
Uncertainty Range ◽  
Field Development ◽  
Production Forecasting ◽  
Production Scheme ◽  
Rock Compressibility

This study accommodates subsurface uncertainties analysis and quantifies the effects on surface production volume to propose the optimal future field development. The problem of well productivity is sometimes only viewed from the surface components themselves, where in fact the subsurface component often has a significant effect on these production figures. In order to track the relationship between surface and subsurface, a model that integrates both must be created. The methods covered integrated asset modeling, probability forecasting, uncertainty quantification, sensitivity analysis, and optimization forecast. Subsurface uncertainties examined were : reservoir closure, regional segmentation, fluid contact, and SCAL properties. As the Integrated Asset Modeling is successfully conducted and a matched model is obtained for the gas-producing carbonate reservoir, highlights of the method are the following: 1) Up to ± 75% uncertainty range of reservoir parameters yields various production forecasting scenario using BHP control with the best case obtained is 335 BSCF of gas production and 254.4 MSTB of oil production, 2) SCAL properties and pseudo-faults are the most sensitive subsurface uncertainty that gives major impact to the production scheme, 3) EOS modeling and rock compressibility modeling must be evaluated seriously as those contribute significantly to condensate production and the field’s revenue, and 4) a proposed optimum production scenario for future development of the field with 151.6 BSCF gas and 414.4 MSTB oil that yields a total NPV of 218.7 MMUSD. The approach and methods implemented has been proven to result in more accurate production forecast and reduce the project cost as the effect of uncertainty reduction.

scholarly journals Evaluation of the Nutrient Composition, In Vitro Fermentation Characteristics, and In Situ Degradability of Amaranthus caudatus, Amaranthus cruentus, and Amaranthus hypochondriacus in Cattle

Animals ◽  
2020 ◽  
Vol 11 (1) ◽  
pp. 18
Author(s):  
Kim Margarette C. Nogoy ◽  
Jia Yu ◽  
Young Gyu Song ◽  
Shida Li ◽  
Jong-Wook Chung ◽  
...  
Keyword(s):  
Crude Protein ◽  
Dry Matter ◽  
Gas Production ◽  
Nutrient Composition ◽  
Neutral Detergent Fiber ◽  
Amaranthus Cruentus ◽  
Amaranthus Caudatus ◽  
Amaranthus Hypochondriacus

The amaranth plants showed high potential feed value as forage for ruminants. An in-depth study of this plant, particularly in cattle, will help extend its utilization as an alternative protein and fiber feed source in cattle feeding. In this study, the nutrient compositions of three different species of amaranth, Amaranthus caudatus L., Amaranthus cruentus L., and Amaranthus hypochondriacus L.—two varieties for each species, A.ca 74, A.ca 91, A.cu 62, A.cu 66, A. hy 30, and A. hy 48—were evaluated. The in vitro technique was used to evaluate the fermentation characteristics such as total gas production, total volatile fatty acids (VFA) concentration, pH, and ammonia concentration of the rumen fluid. Moreover, the effective degradabilities of dry matter (EDDM) and crude protein (EDCP) of the amaranth forages were determined through in situ bag technique. The amaranth forages: A. caudatus, A. cruentus, and A. hypochondriacus showed better nutritive value than the locally produced forages in Chungcheong province of Korea. The CP of the amaranth ranged from 11.95% to 14.19%, and the neutral detergent fiber (NDF) and acid detergent fiber (ADF) contents ranged from 45.53% to 70.88% and 34.17% to 49.83%, respectively. Among the amaranth varieties, A. hypochondriacus 48 showed the most excellent ruminant feed nutrient quality (CP, 14.19%; NDF, 45.53%; and ADF, 34.17%). The effective degradabilities of dry matter (EDDM; 33–56%) and crude protein EDCP (27–59%) of the amaranth were lower compared to other studies, which could be due to the maturity stage at which the forages were harvested. Nonetheless, A. hypochondriacus 48 showed the highest EDDM (56.73%) and EDCP (59.09%). The different amaranth species did not differ greatly in terms of total VFA concentration or molar proportions, total gas production, or ammonia-N concentration. The high nutrient composition, and highly effective degradability of dry matter and crude protein, coupled with the favorable fermentation characteristics, suggest that the amaranth forages showed good to excellent feed quality for cattle.

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