Baghban Salehi, Mahsa (Chemistry & Chemical Engineering Research Center of Iran) | Mousavi Moghadam, Asefe (Chemistry & Chemical Engineering Research Center of Iran) | Jarrahian, Khosro (Heriot-Watt University)
Preformed Particle Gel (PPG) is an appropriate solution for conformance control and managing water production in low permeable reservoirs. Rheological behavior evaluation of these deformable particles is a key factor in designing composition to achieve the best conformance control treatment due to the viscoelastic behavior of these particles along with their swelling. The purpose of this paper is to evaluate the network parameters of PPGs through swelling tests, rheology and determining its role in maintaining their structural strength. Several PPG hydrogels were prepared by varying the concentrations of polyacrylamide and Cr(OAc)3 as copolymer and crosslinker, respectively. The characterization of these hydrogels was performed using Scanning Electron Micrographs (SEM), Electron Dispersion X-ray analysis (EDX), Environmental Scanning Electron Microscopy (ESEM), ThermoGravimetric Analysis (TGA), and Differential ThermoGravimetry (DTG). The correlation between reaction conditions and network parameters of polymer networks such as, molecular weight of the polymer chain between two neighboring crosslinks, crosslink density, and size fraction have been determined. The swelling of the hydrogels was found through the Fickian diffusion mechanism. In this case, the diffusion rate of water in the 3D structure of the hydrogel is less than the relaxation of the polymeric chain, resulting in a significant increase in the PPG particles volume. As PPG was invaded such as in the reservoir by formation water or oil, repeatedly, the sensitivity factor was measured to ensure the swelling in the electrolyte solution. Based on rheological tests, the dynamic modulus of the swelled PPG was strongly dependent on the concentration and consequently network parameters. Also, through the optimization of the network parameters, the appropriate composition from the point of view of strength (complex modulus of 4×104 Pa) and salt sensitivity of 0.5 was presented. In addition, the results of the TGA/DTG test demonstrated the thermal stability of the sample was in temperature range 245 to 340°C. The determination and analysis of the network parameter is the novel technique for predicting the hydrogel performance in porous media and investigating its strength under harsh reservoir conditions. In other words, determination of the network parameter can be a shortcut to ensure the success of the gel performance in porous media.
Hydraulic fracturing is often performed using resin-coated proppants to minimize proppant flowback during hydrocarbon production, whether the resin is precoated or coated on-the-fly as the treatment is pumped. Resin-fracturing fluid interaction can have a negative effect on fluid stability or resin consolidation, or both. This paper examines the effects of resin-fluid interactions on fluid stability, proppant consolidation strength, and strategies to mitigate the effects.
Components of resins can change the fracturing fluid stability by interacting with crosslinker or breaker, or by changing the fluid pH. To offset the effect of a resin, the breaker/crosslinker/buffer concentration should be tuned while pumping resin-coated proppant. Similarly, resin-fluid interaction can decrease consolidation strength by disturbing resin-curing kinetics or reducing grain-to-grain contact, which can increase the possibility of proppant flowback during production. The influence of resins on fracturing fluid stability was evaluated by conducting rheology testing. The effect of fracturing fluids on the consolidation strength of resin was evaluated by comparing unconfined compressive strength (UCS) of proppant packs.
The stability of zirconate and borate crosslinked guar fluids, when treated with coated on the fly liquid resin-coated proppant (LRCP), was lower than non-treated fluids at 260°F as a result of breaker activation by the resin components. The desired fluid stability was attained by lowering breaker concentration in liquid resin-treated fluid. During another round of testing, a second type of LRCP, based on different chemical functionality, increased the stability of synthetic polymer fluid at 400°F. Likewise, a rise in fluid stability was observed when guar fluid was treated with resin pre-coated proppant (RCP) at 200 and 250°F. The improved fluid stability is associated with reduction in active breaker concentration in the presence of furan resin and RCP. The UCS value of the proppant pack prepared from fracturing fluid-treated RCP was ~16 to 45% lower than the proppant pack without this fluid treatment. Additionally, the UCS value of proppant pack prepared using fracturing fluid-treated LRCP decreased by ~30%. However, the measured UCS value of LRCP pack with fracturing fluid exposure was higher than the RCP pack measured value even without exposure to this fluid.
Incorporating LRCP instead of using RCP during fracturing operations could address the proppant flowback issue and possibly result in higher conductivity of propped fractures. It could help ensure economic production rates and prevent costs associated wellbore cleanup, downhole tool damage, erosion and damage to the tubular, chokes, valves and separators, and refracturing of the well. Ultimately, it could help maintain a lower cost per barrel of oil equivalent (BOE).
In recent decades, the widespread implementation of horizontal drilling and multistage hydraulic fracturing in unconventional plays has increased the use of fresh water in oilfield operations. The formulation of fracturing fluids with non-fresh water sources such as seawater or produced water are attracting more attention due to the long term sustainability of non-fresh water use.
Fracturing fluids using seawater are available in the industry. But the compatibility between the composition of local seawater and reservoir brine can add complication in the formation damage consideration. For example, if a seawater rich in sulfate comes in contact with formation brine rich in calcium or barium, severe scale can be expected if the proper caution is not taken. Treated seawater with nano-filtration to removal sulfate is a good practice to eliminate this problem. This paper describes a fracturing fluid formulated by using nanofiltered seawater for high temperature applications at 300 to 325°F. The crosslinked fracturing fluid formulation was optimized in the lab to accommodate the nanofiltered seawater, resulting in satisfactory fluid performance thereby enabling the fracturing operations to conserve fresh water.
A high-temperature crosslinked fracturing fluid system was prepared with the nanofiltered local seawater. The fluid system showed robust stability at high temperatures. For example, the fluid viscosity stayed above 400 cP (at 100 sec−1 shear rate) for 2 hr at 300°F, with 45 ppt of the polymer loading. At 325°F, the fluid maintained viscosity above 300 cP for 2 hr with 60 ppt of the polymer loading. The nanofiltered seawater-based fluids was found to be compatible with a number of commonly used fluid additives including biocide, surfactant, and clay stabilizer. The fluid system also showed low formation damage and scaling tendencies. In the coreflow tests at 300°F, a regained permeability of greater than 95% was obtained. In the scaling tests without the presence of scale inhibitor at 300°F, traceable (<0.01 wt %) amount of scale was observed in the mixture of the nanofiltered seawater and high total dissolved solids (TDS) formation brine. Overall, it was found using the nanofiltered seawater can lead to better fluid stability at elevated temperatures, better fluid cleanup, and reduced downhole scaling tendency.
By careful selection of the fluid components, the nanofiltered seawater-based fluid relieve the burden of needing fresh water for hydraulic fracturing treatment, allowing for a more sustainable approach. This paper discusses the technical functions of the key fluid additives used in the fracturing fluid preparation.
Zhu, Daoyi (China University of Petroleum, Beijing) | Hou, Jirui (China University of Petroleum, Beijing) | Wei, Qi (China University of Petroleum, Beijing) | Chen, Yuguang (China University of Petroleum, Beijing)
The PG Reservoir in Jidong Oil Field is at a depth of approximately 4500 m with an extremely high temperature of approximately 150°C. The average water cut has reached nearly 80%, but the oil recovery is less than 10% after only 2 years of waterflooding process. It is of great importance to develop a high-temperature-resistant plugging system to improve the reservoir conformance and control water production. An in-situ polymer-gel system formed by the terpolymer and a new crosslinker system was developed, and its properties were systematically studied under the condition of extremely high temperature (150°C). Suitable gelation time and favorable gel strength were obtained by adjusting the concentration of the terpolymer (0.4 to 1.0%) and the crosslinker system (0.4 to 0.7%). An increase of polymer and crosslinker concentration would decrease the gelation time and increase the gel strength. The gelant could form continuous 3D network structures and thus have an excellent long-term thermal stability. The syneresis of this gel system was minor, even after being heated for 5 months at the temperature of 150°C. The gel system could maintain most of the initial viscosity and viscoelasticity, even after experiencing the mechanical shear or the porous-media shear. Core-flow experiments showed that the gel system could have great potential to improve the conformance in Jidong Oil Field.
Hydraulic fracturing has become a common practice in the petroleum industry, and several systems have been developed to obtain a suitable crosslinked polymer for the treatment. However, each system has its strengths and weaknesses. This study aims to investigate the effect of three different ligand types attached to zirconium (Zr) on the performance of carboxymethylhydroxypropylguar (CMHPG) crosslinked with Zr-based crosslinkers with the different ligands. The shear recoverability and rapid viscosity buildup at the high pH of Zr-based crosslinkers were overcome by a new aluminum-zirconium (Al-Zr) dual crosslinker in this research.
The polymer used was CMHPG, and the tests were conducted at pH of 3.8 and 10.8. One of the factors that affects the gel performance is the type of ligand attached to the Zr. Because the Zr-based crosslinkers are shear-sensitive, ligands were introduced to delay the crosslinking until the fluid passes the high-shear environments (perforations). Therefore, in this study, lactate, propylene glycol, and triethanolamine (TEA) were studied as ligands attached to the Zr. Two Zr crosslinkers with almost the same concentration of Zr can display different performances if the ligand attached to the Zr is not the same.
The rapid viscosity buildup at high pH had always been a limitation of Zr crosslinkers; however, a new Al-Zr dual crosslinker was introduced in the present study to address this limitation. The Al-Zr crosslinker outperformed all the other crosslinkers examined in the present study. Immediate viscosity buildup at a high pH and a lack of shear recoverability of Zr-based crosslinkers was addressed through the Al-Zr crosslinker. The Al-Zr crosslinker introduced in this study is one compound that is easy to use in the field. The Al-Zr crosslinker performance was compared with the boron-zirconium (B-Zr) crosslinker: Both had lactate as a ligand attached to them. Among all the Zr-based crosslinkers in this study, the Zr crosslinker with lactate and propylene glycol as a ligand performed the best. The CMHPG crosslinked with each of the crosslinkers was tested for proppant-carrying purposes along with static leakoff rates. The results revealed gel-proppant-suspending capabilities and acceptable leakoff rates.
Extensive laboratory research is a key to a successful field treatment. These results indicate that fracturing fluids are complex, and the ligand type is one of the important factors in determining the final properties of fracturing fluids. Therefore, the results of this study will assist in developing Zr-based crosslinkers that address their current shortcomings.
Zhu, Daoyi (China University of Petroleum, Beijing) | Hou, Jirui (China University of Petroleum, Beijing) | Chen, Yuguang (China University of Petroleum, Beijing) | Wei, Qi (China University of Petroleum, Beijing) | Zhao, Shuda (Missouri University of Science and Technology) | Bai, Baojun (China University of Petroleum, Beijing, at Karamay and Missouri University of Science and Technology)
A terpolymer-gel system using low toxic polyethylenimine (PEI) as the crosslinker was developed for conformance improvement in high-temperature reservoirs. Suitable gelation time (GT), gel strength, and thermal stability could be obtained by selecting PEI molecular weight and adjusting terpolymer concentrations. With the increase of terpolymer concentration, GT decreases and the gel strength increases. However, in this research, the effect of PEI concentration on the gelation performance was much less obvious than that of the polymer concentration. Very low concentrations of sodium chloride (NaCl) can slightly shorten the GT. After critical concentrations were reached, the authors determined that the ions will delay the crosslinking reaction. Moreover, the addition of sodium carbonate (Na2CO3) can also lengthen GT. The gel systems were able to maintain thermal stability at 150°C. Uniformly distributed 3D network microstructures and the small size of the gel-grid pores made the network structure maintain thermal stability. The use of the terpolymergel-system gelation mechanism crosslinked by PEI can help petroleum engineers better understand and apply this terpolymer-gel system.
Long, Yifu (Missouri University of Science and Technology) | Yu, Bowen (Missouri University of Science and Technology) | Zhu, Changqian (Research Institute of Petroleum Exploration and Development, PetroChina)
Conformance improvement for ultra-high-temperature (130 °C) reservoirs is challenging due to the poor thermostability of conventional preformed particle gel (CPPG). To overcome the defect of thermal degradation, a novel hydrostable PPG (HT-PPG) was developed using the high-temperature tolerant crosslinker. In this work, a comparative study between the HT-PPG and CPPG has been presented in respects of their swelling behaviors, rheology properties and thermal stabilities. Particle swelling behaviors and viscoelasticities were firstly assessed in ambient. Using the swollen particles, a long-term aging at 130 °C underwent during which the physical status was monitored through high pressure vials (HPV). Furthermore, characterizations involved Scanning Electron Microscope (SEM) and Fourier Transform-Infrared Spectroscopy (FT-IR) were performed for both virgin and aged specimen. Thereby, an observation of gel microstructures and elucidation upon bonds or functional groups were provided. In addition to aging tests, we deployed the Differential Scanning Calorimetry (DSC) to investigate the inflection temperature as another indicator of particle thermostability. Attributed to the hydrostable crosslinker, the HT-PPG withstood 130 °C for at least 90 d. It was found that the HT-PPG effectively maintained its particulate shape, whereas, the CPPG completely degraded after 3-d aging. The HT-PPG maintained 28.8% of its initial storage modulus (G′). On the contrary, the normalized elasticity (G′/G0‘) of CPPG was only 0.43%. The SEM morphologies illustrated HT-PPG kept its rigid microstructure even after 90-d aging, while indicated destruction within CPPG network. According to FT-IR characterization, the decomposition of pristine crosslinker, N,N′-Methylenebisacrylamide in CPPG may account for its instability. DSC measurements furtherly demonstrated the favorability of HT-PPG in which HT-PPG exhibited a higher inflection temperature of 133.1 °C, however, CPPG only had an inflection temperature of 127.7 °C. This work turned out the novel HT-PPG could withstand ultra-high-temperature (130 °C) for more than 90 d, maintaining its particulate shape and viscoelasticity. This a durable plugging agent was notably superior to the CPPG, offering a candidate material for the conformance improvement in ultra-high-temperature reservoirs.
Almubarak, Tariq (Texas A&M University) | Li, Leiming (Aramco Services Company) | Nasr-El-Din, Hisham (Texas A&M University) | Ng, Jun Hong (Texas A&M University) | Sokhanvarian, Khatere (Sasol Chemical) | Alkhaldi, Mohammed (Saudi Aramco) | Almubarak, Sama (Saudi Aramco)
In order to satisfy the demand for oil and gas, it becomes increasingly necessary to produce from formations that are deeper, have low permeability, and higher temperature. Conventionally, hydraulic fracturing fluids make use of viscosifiers such as guar and its derivatives to generate the rheological properties required during the fracturing process. However, to withstand the high-temperature environments, higher loadings of polymer is required. This leads to an increase in polymer and additive concentrations. Most importantly, these higher loading fluids do not break completely, and generate residual polymer fragments that can plug the formation and reduce fracture conductivity significantly.
This work builds on previous work which introduced a new hybrid dual polymer hydraulic fracturing fluid that was developed for high-temperature applications. The fluid consists of a guar derivative and a polyacrylamide-based synthetic polymer. Compared to conventional fracturing fluids, this new system is easily hydrated, requires less additives, can be mixed on the fly, and is capable of maintaining excellent rheological performance at low polymer loadings. In this work, the fluid is further optimized to withstand even higher temperatures up to 400°F.
Total polymer loadings of 30 lb/1,000 gal and 40 lb/1,000 gal dual polymer fracturing fluid were tested in this work and were prepared in the ratio of 1:1 and 1:2 (CMHPG: Synthetic). They were then crosslinked with a metallic crosslinker and placed in a HPHT rheometer to measure the viscosity between 200 and 400°F. After observing the failure temperature of the mixtures, additives such as buffers, crosslinking delayers, and oxygen scavengers were added and tested at temperatures above that point. The type of crosslinker used was also varied to observe the effects of the rate of release of the metallic crosslinker on thermal stability.
The results indicate that the 1:2 (CMHPG: Synthetic) mixture performed better at temperatures exceeding 330°F than the 1:1 mixture. The failure point of both mixtures was observed to be 350°F for the latter while the former failed at 370°F. The addition of a crosslinker that allowed a more controllable release was observed to improve the thermal stability of the fluid mixture above 370°F by increasing the polymer's shear tolerance. The addition of additives to the mixture was shown to improve the thermal stability of the solution to varying degrees. Of the three additives, the most significant enhancement came from the addition of oxygen scavengers while the least was from the buffer solution.
Nagar, Ankesh (Cairn Oil and Gas, Vedanta Limited) | Dangwal, Gaurav (Cairn Oil and Gas, Vedanta Limited) | Pandey, Nimish (Cairn Oil and Gas, Vedanta Limited) | Jain, Akanksha (Cairn Oil and Gas, Vedanta Limited) | Parasher, Arunabh (Cairn Oil and Gas, Vedanta Limited) | Deshpande, Mayur (Halliburton) | Gupta, Vaibhav (Halliburton) | Pande, Karan (Halliburton)
Increasing water cut in oil-producing zones is a common issue faced by operators, particularly for mature fields. Currently, where most of the decisions are governed by economics, incurring additional expenses with activities such as handling produced water becomes extremely undesirable. Depending upon the nature of the zone, one effective solution to this issue is chemical isolation. This paper undertakes this issue, discussing a case study of a successful zonal isolation operation using an organically crosslinked polymer sealant in a fractured zone with a gravel pack and screen completion for a reservoir with a subhydrostatic nature.
This zone was an initial oil producer in FM-01 sand of the Mangala onshore oil field and had been stimulated in 2011 with a fracture-pack completion. The zone was completed with screens and a gravel pack with 16/30-mesh sand and 5.5-in. screens across the producing interval. During a period of time, the zone (FM-01) began to produce a significant amount of water, resulting in excessive water cut. To mitigate the issue, it was decided to completely isolate the zone using an organically crosslinked polymer system as a porosity fill sealant. When prepared in the appropriate concentration, subject to reservoir temperature, this low-viscosity formulation (40 to 80 cp) turns into a permanent rigid gel with time. The particular challenges of this operation were the presence of high permeability streaks because of stimulation by hydraulic fracturing, extra pore space because the perforated interval lay within the gravel-packed screens, and the subhydrostatic nature of the reservoir. Extensive laboratory testing was performed to optimize the formulation at the desired temperature, measuring the time necessary for the viscosity to begin increasing and the minimum total time necessary to form a rigid gel.
The case study discussed in this paper features the successful application of the treatment using the spot-and-squeeze method with coiled tubing (CT) for the isolation of the zone. After allowing the setting time, pressure tests were performed, indicating positive isolation of the zone. After the pressure test, a jet pump was installed, and a drawdown was created to flow the zone. It was observed that production post operation was almost 95% less than production before operation at the same pressure drawdown, indicating approximately 100% zone isolation.
Almubarak, Tariq (Texas A&M University) | Ng, Jun Hong (Texas A&M University) | Sokhanvarian, Khatere (Sasol Performance Chemicals, Texas A&M) | AlKhaldi, Mohammed (Saudi Aramco EXPEC ARC) | Nasr-El-Din, Hisham (Texas A&M University)
As exploration for oil and gas continues, it becomes necessary to produce from formations that are deeper, have low permeability, and higher temperature. Conventionally, guar and its derivatives have been successfully utilized as hydraulic fracturing fluids. However, they require higher polymer loading to withstand the high-temperature environments. This leads to an increase in mixing time and additive requirements. Most importantly, they do not break completely and generate residual polymer fragments that can plug the formation and reduce fracture conductivity significantly.
In this work, a new hybrid dual polymer hydraulic fracturing fluid is developed for high-temperature applications. The fluid consists of a guar derivative and a polyacrylamide-based synthetic polymer. Compared to conventional fracturing fluids, this new system is easily hydrated, requires fewer additives, can be mixed on the fly, and is capable of maintaining excellent rheological performance at low polymer loadings.
The polymer mixture solutions were prepared at concentrations ranging from 20 to 40 lb/1,000 gal at a ratio of 2:1, 1:1, and 1:2. The fluids were crosslinked with a metallic crosslinker and broken with an oxidizer at 300-350°F. Testing focused on crosslinker to polymer ratio analysis to effectively lower loading while maintaining sufficient performance to carry proppant at these harsh conditions. HP/HT rheometer was used to measure viscosity and elastic modulus. HP/HT see-through cell was utilized for proppant settling.
Results indicate that the dual polymer fracturing fluid is able to generate stable viscosity at 300-350°F and 100 s-1. Results show that the dual polymer fluid can generate higher viscosity compared to the individual single polymer system. Also, properly understanding and tuning the crosslinker to polymer ratio generates excellent performance even at 20 lb/1,000 gal. The two polymers form a shared crosslinking network that improves proppant carrying capacity at lower polymer loadings and high temperatures. It also demonstrates a clean and controlled break performance with an oxidizer.
The major benefit of using a mixed polymer system is to reduce polymer loading at harsher conditions. Lower loading is highly desirable because it reduces material cost, eases field operation and lowers damage to the fracture face, proppant pack and formation.