Seawater-based fracturing fluids are favorable in offshore locations because of the readily available seawater. This can minimize or even eliminate costly vessel trips necessary to transport fresh water to rig sites, while also reducing rig downtime. This paper presents the development of a low-residue fracturing fluid that uses seawater as a base fluid and also presents the results of successful field applications. This seawater-based fracturing fluid uses a low-residue polymer crosslinked with zirconium that has a pH of less than 10 to minimize damage and residue encountered using other fluids. The fluid was tested for rheological properties, proppant-carrying capacity, retained permeability, and compatibility with formation fluid. To improve timing and efficiency of operations, a multistage fracturing completion was used wherein each fracture sleeve was opened by dissolvable balls. Three wells were treated in the offshore Romanian Lebada fields. Well A comprised high sandstone content. Wells B and C comprised a higher limestone content but contained too much clay and sandstone for an acid fracturing treatment. Both wells exhibited a moderate-to-high number of natural fractures. Because of moderate permeabilities in the range of 0.1 to 2 md, crosslinked fluid was used in the pad and subsequent proppant-laden stages. During development evaluations, the fluid remained stable for approximately 1 hour at 325°F with a gel loading of 6 kg/m3 (50 lbm/1000 gal) The thermal stability of the fluid system was improved when compared to the alternative hydroxypropyl guar (HPG) fluid. A delayed crosslinker was used to maintain low-friction pressure during the treatment. No scale formation was observed. The target reservoir temperature was 199°F. Additional testing optimized gel loading at 3.6 kg/m3 (30 lbm/1000 gal). The fluid suspended the proppant for approximately 2 hours. Less than 1% residue was formed after fluid breakdown, which was much lower than the residue generated by the HPG fluid. A regained permeability of 92% was obtained from a sandstone core, demonstrating the low-damaging nature of the fluid. The broken fluid was fully compatible with crude oil and completion brine. Twenty total stages of hydraulic fracturing operations were designed and executed successfully in the three horizontal wells. A 16/20-mesh resin-coated proppant (RCP) was used at a maximum concentration of 720 kg/m3 (6 lbm/gal) during the tail stage. A total of 1533 tonnes (~3.38 million lbm) of proppant was pumped in 5915 m3 (~1.56 million gal) of crosslinked fluid. The seawater-based fluid properties present an innovative approach for addressing the water requirement issue for offshore stimulation operations. This fluid is an excellent candidate for fracturing operations and can help operators maintain low costs per barrel of oil equivalent (BOE).
Emulsified hydrochloric (HCl) acid has been used in both fracture and matrix acidizing of carbonate reservoirs to help penetrate deeper into the reservoir before spending. The emulsion stability and adequate corrosion inhibition are critical requirements of this blend, which are challenging to accomplish using emulsified acids of high HCl acid concentration (>26%) at high temperatures (>250°F) because many corrosion inhibitors used in the industry can severely affect emulsion stability by interacting with the emulsifier. The requirement of other additives, such as iron-control additives, surfactants other than the emulsifier, H2S scavengers, etc., can further add to the challenges. This work presents the laboratory optimization of 26% emulsified HCl-acid blends for use at temperature ranges between 250 and 300°F. Quaternary ammonium salt based Inhibitor I-C and a propargyl alcohol based Inhibitor I-N were used in this study. One inorganic halide based (IN-H) and one organic acid based (IN-O) intensifier were used to achieve adequate corrosion inhibition. A single commercial blend of surfactants was used for all the tests. Based on the high-pressure high-temperature (HPHT) static corrosion tests, Inhibitor I-C performed better than Inhibitor I-N at 275°F. However, Inhibitor I-C was found more damaging to emulsion stability than Inhibitor I-N. At 250°F, the performances of both inhibitors were comparable. A common misconception that prevails in the industry is that a stable emulsified acid can ensure a successful acid job without (or with a very little amount of) corrosion inhibitor. It was clearly evidenced during this study that the emulsion stability alone does not ensure the protection of alloys from corrosion. Using a suitable corrosion inhibitor in appropriate concentration is as equally important as emulsion stability for successful completion of an emulsified acid job without encountering severe corrosion problems.
Seawater-based fracturing fluids are favorable in offshore locations because of the readily available seawater. This minimizes or even eliminates costly vessel trips that are necessary to transport fresh water to rig sites, while also reducing rig downtime. This paper presents the development of a low-residue fracturing fluid that uses seawater as a base fluid and the results of successful field applications. This seawater-based fluid uses a low-residue polymer crosslinked with zirconium having a pH of less than 10 to minimize damage and residue encountered using other fluids. The fluid was tested for rheological properties, proppant-carrying capacity, retained permeability, and compatibility with formation fluid. To improve timing and efficiency of operations, multistage fracturing completion was used wherein each fracture sleeve was opened by dissolvable balls. Two sidetrack wells were treated in the offshore Romanian Lebada fields. Well A comprised high sandstone content. Well B comprised a higher limestone content but contained too much clay and sandstone for an acid fracturing treatment. Both wells exhibited a moderate-to-high number of natural fractures. Because of moderate permeabilities in the range of 0.1 to 2 md, crosslinked fluid was used in the pad and subsequent proppant-laden stages. The seawater-based fracturing fluid was not expected to generate damaging effects on reservoir productivity. During development, the fluid remained stable for approximately 1 hour at 325°F with a gel loading of 6 kg/m3. The thermal stability of the fluid system was improved when compared to the alternative hydroxypropyl guar (HPG) fluid. A delayed crosslinker was used to maintain low-friction pressure during the treatment. No scale formation was observed. The target reservoir temperature was 199°F. Additional testing optimized gel loading at 3.6 kg/m3. The fluid suspended the proppant for approximately 2 hours. Less than 1% residue was formed after fluid breakdown, which was much lower than the residue generated by the HPG fluid. A regained permeability of 92% was obtained from a sandstone core, which demonstrates the low-damaging nature of the fluid. The broken fluid was fully compatible with crude oil and completion brine. Eleven hydraulic fracturing operations were designed and executed successfully in both horizontal sidetrack wells. A 16/20-mesh resin-coated proppant (RCP) was used at a maximum concentration of 720 kg/m3 in the tail stage. A total of 851 tonnes of proppant was pumped in 3156-m3 crosslinked fluid. The seawater-based fluid properties present an innovative approach to address the water requirement issue for offshore stimulation operations. This fluid is an excellent candidate for fracturing operations and can help operators maintain low costs per barrel of oil equivalent (BOE).
Hydraulic fracturing has remained a fundamental technique for stimulation of oil and gas reservoirs for enhanced or economic recovery of hydrocarbons from tight formations for more than 60 years. Transporting proppant downhole without any interruption and then to obtain maximum recovery of fracturing fluids are two important criteria for successful hydraulic fracturing. To achieve such objectives, the fracturing fluid should demonstrate good viscosity and complete cleanup of gelling agents. Because wells are exploited at both shallow and great depths in environments of moderate to very high temperatures and pressures, fracturing fluid selection is fundamental. Fracturing fluids prepared by crosslinking guar, guar derivatives, and other naturally occurring polymers with borate or metal crosslinkers often exhibit instability at very high temperatures. The primary reason for instability of the fracturing fluid is because strength of the bonds between the polymer chain and crosslinker decreases sharply in addition to breakdown of the glycosidic bonds between monomer units of the polymer chain beyond 375°F. Additionally, metal crosslinked bonds are prone to shear degradation, creating doubt for a successful stimulation treatment in high-temperature extended-reach wells. To address these issues, a synthetic gelling-agent-based fracturing fluid that can work at temperatures greater than 400°F was developed. The gelling agent is a terpolymer, which can be crosslinked with a zirconium-based crosslinker. This paper discusses evaluation and performance of an extreme temperature fracturing fluid. This fracturing fluid system has sufficient proppant carrying viscosity and provides efficient post-treatment cleanup using delayed oxidized breaker. Analysis of fluid viscosity stability and delayed oxidizing breaker usage is presented in addition to performance parameters such as regained permeability and fluid loss. The study illustrates performance of the synthetic gelling-agent-based fracturing fluid at temperatures ranging from 380 to 440°F.
For a successful hydraulic fracturing operation, two of the most important properties required from fracturing fluids are transport proppant into the fractured zone and minimum damage to formation and proppant pack conductivity. As the fluid is pumped downhole, it experiences thermal and shear thinning. Shear recovery and thermal stability are critical in terms of successful fracture creation and proppant placement. These fluid properties can be controlled by proper selection of crosslinker and linkable groups. Thermal stability of fluid at high temperatures can be increased by proper selection of gel stabilizers and it also reduces the amount of gelling agent to be used. Conventional gel stabilizer contains sulfur which could contribute to H 2 S gas when consumed by sulfate reducing bacteria. H 2 S gas is not only corrosive in nature but also harmful to health and thus, although it performs well, several operators seek sulfur-free stabilizers that can perform equivalent to sulfur-based compounds.This paper describes a sulfur-free gel stabilizer developed for enhancing the stability of fracturing fluid, allowing a lower concentration of gelling agent. This gel stabilizer is sulfur-free, nonhazardous, and biodegradable. It also provides better stability for fluids compared to conventional sulfur containing gel stabilizers.Further showcased is the improvement in stability of crosslinked fracturing fluid using the sulfur-free stabilizer under high temperature (HT) conditions of 280 to 320°F. Rheological tests performed using a Chandler high-pressure/high-temperature (HP/HT) viscometer with and without stabilizer are discussed. Results shows a significant change in terms of fluid stability in the presence of this new stabilizer as it provides better stability compared to conventional sulfur containing stabilizer. Also, shear sensitivity tests performed under multiple high shear rate cycles between 100-935-1700 s -1 showed excellent shear recovery after every high shear cycle by completely rehealing in less than 30 seconds.
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