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Fluid-Loss-Control Additives (FLAs) are used to maintain a consistent fluid volume within a cement slurry to ensure that the slurry performance properties remain within an acceptable range. The variability of each of these parameters (slurry performance properties) is dependent upon the water content of the slurry. If the water content is less than intended, the opposite will normally occur. The magnitude of change is directly related to the amount of fluid lost from the slurry. Because predictability of performance is typically the most important parameter in a cementing operation, considerable attention has been paid to mechanical control of slurry density during the mixing of the slurry to assure reproducibility.
John, Blevins (Hibernia Resources) | Van Domelen, Mark (Downhole Chemical Solutions) | West, Zach (Downhole Chemical Solutions) | Rall, Jason (Downhole Chemical Solutions) | Wakefield, Drake (Downhole Chemical Solutions)
Abstract Since the early development of unconventional resource plays, slickwater fracturing fluids have expanded rapidly and are now the most common type of fluid system used in the industry. Slickwater and viscosifying friction reducer (VFR) fluids consist of polyacrylamide (PAM) polymers and are typically delivered to location in a liquid form such as a suspension or emulsion in a hydrocarbon-based carrier fluid. Recently, advances in dry powder delivery operations have provided unique advantages over the liquid versions of FRs including cost savings and improved health, safety and environmental (HSE) aspects. This paper describes the dry powder delivery process and describes the advantages that this new technology has brought to field operations. The method involves delivering polyacrylamide powder for slickwater fracturing treatments directly into the source water on location, thereby eliminating the use of liquid polymer slurries or emulsions. Liquid friction reducers typically contain 20-30% active polymer loading, with the remaining volume being the carrier fluid to keep the polymer in suspension. By delivering 100% powder, several benefits are gained including elimination of truck deliveries of FR liquids to location, reduction of total chemical volumes by 70-80%, reduction of spill hazards, and lower overall chemical costs. Different powders are available for various applications including the use of fresh or produced water, and viscosifying or non-viscosifying polymers. The key technology for "dry on the fly" (DOTF) operations is the powder delivery equipment. Due to the different molecular structures between polyacrylamide and guar polymers, delivering PAM is more technically challenging than guar and requires much higher mixing energy to achieve proper dispersion and hydration. The delivery system described in this paper uses a unique technology which creates the necessary conditions for powder mixing and has been successfully applied on over 350 wells since early 2019, with over 7,000 tons of polymer delivered.
Abstract As our industry is tapping into tighter carbonate reservoirs than in the past, completion techniques need to be improved to stimulate the low-permeability carbonate formation. Multistage acid fracturing technique has been developed in recent years and proved to be successful in some carbonate reservoirs. A multistage acid fracturing job is to perform several stages of acid fracturing along a horizontal well. The goal of acid fracturing operations is to create enough fracture roughness through differential acid etching on fracture walls such that the acid fracture can keep open and sustain a high enough acid fracture conductivity under the closure stress. In multistage acid fracturing treatments, acid flow is in a radial flow scenario and the acid etching process can be different from acid fracturing in vertical wells. In order to accurately predict the acid-fracture conductivity, a detailed description of the rough acid-fracture surfaces is required. In this paper, we developed a 3D acid transport model to compute the geometry of acid fracture for multistage acid fracturing treatments. The developed model couples the acid fluid flow, reactive transport and rock dissolution in the fracture. We also included acid viscous fingering in our model since viscous fingering mechanism is commonly applied in multistage acid fracturing to achieve non-uniform acid etching. Our simulation results reproduced the acid viscous fingering phenomenon observed from experiments in the literature. During the process of acid viscous fingering, high-conductivity channels developed in the fingering regions. We modeled the acid etching process in multistage acid fracturing treatments and compared it with acid fracturing treatments in vertical wells. We found that due to the radial flow effect, it is more difficult to achieve non-uniform acid etching in multistage acid fracturing treatments than in vertical wells. We investigated the effects of perforation design and pad fluid viscosity on multistage acid fracturing treatments. We need to have an adequate number of perforations in order to develop non-uniform acid etching. We found that a higher viscosity pad fluid helps acid to penetrate deeper in the fracture and result in a longer and narrower etched channel.
Wang, Chengwen (China University of Petroleum (East China), Shandong Key Laboratory of Oilfield Chemistry (Corresponding author) | Chen, Zehua (email: email@example.com)) | Chen, Erding (China University of Petroleum (East China) (Corresponding author) | Liu, Junyi (email: firstname.lastname@example.org)) | Xiao, Fengfeng (Drilling Technology Research Institute of Shengli Petroleum Engineering Corporation Limited) | Zhao, Hongxiang (Drilling Technology Research Institute of Shengli Petroleum Engineering Corporation Limited)
Summary Removal of useless and submicrometer-sized solids from drilling fluid, which exert significant effects on drilling performance, is a crucial part of sustainable and eco-friendly circulation in drilling operations. However, current solid-control methods for drilling-fluid reuse and recirculation, such as electronic-adsorption and chemical-flocculation methods, are associated with high cost and low efficiency and/or pollution of drilling fluid. In this study, a novel method using ultrasonic waves has been proposed to remove unwanted submicrometersized solids from polysulfonate drilling fluids. The results show that the suspension stability, viscosity, and particle size can all be significantly reduced, while the solid-separation ratio of the drilling fluid can be greatly enhanced by ultrasonic-wave treatment. The parameters of ultrasonic waves are optimized to be power of 3 kW, treating time of 30 minutes, treating frequency of 20 kHz, and ventilation (i.e., air) for 5 minutes in a laboratory scale. The scanning electron microscope (SEM) analysis shows that solid particles exhibit more obvious crystal morphology after ultrasonic-wave treatment, indicating that the breaking of gel-structure of drilling fluid due to the cavitation, mechanical, and heat effects of ultrasonic waves is the main mechanism for decreasing the suspension stability. Thus, the proposed ultrasonicassisted technique has a high potential for removing undesirable solids from drilling fluid and fulfilling its recirculation in a cost-effective and environmentally friendly manner. This new technology has been successively applied to 12 wells, and good results were obtained. Introduction The drilling fluid is known as the blood of the drilling operation, and it plays a vital role in balancing formation pressure, carrying and suspending drilling cuttings, transmitting water power, lubricating the drillstring, and keeping the drillbit cool and clean.
Abstract Application of chemical enhanced oil recovery (C-EOR) processes to low-permeability sandstone reservoirs (in the 10-100 mD range) can be very challenging as strong retention and difficult in-depth propagation of polymer and surfactant can occur. Transport properties of C-EOR chemicals are particularly related to porous media mineralogy (clay content). The present experimental study aimed at identifying base mechanisms and providing general recommendations to design economically viable C-EOR injection strategies in low permeability clayey reservoirs. Polymer and surfactant injection corefloods were conducted using granular packs (quartz and clay mixtures) with similar petrophysical characteristics (permeability 70-130 mD) but having various mineralogical compositions (pure quartz sand, sand with 8 wt-% kaolinite and sand with 8 wt-% smectite). The granular packs were carefully characterized in terms of structure (SEM) and specific surface area (BET). The main observables from the coreflood tests were the resistance and residual resistance factors generated during the chemical injections, the irreversible polymer retention and the surfactant retention in various injection scenarios (polymer alone, surfactant alone, polymer and surfactant). A first, the impact of the clay contents on the retention of polymer and surfactant considered independently was examined. Coreflood results have shown that retention per unit mass of rock strongly increased in presence of both kaolinite and smectite, but not in the same way for both chemicals. For polymer, retention was about twice higher with kaolinite than with smectite, despite the fact that the measured specific surface area of the kaolinite was about 5 times less than that of the smectite. Conversely, for surfactant, retention was much higher with smectite than with kaolinite. Secondly, the impact of the presence of surfactant on the polymer in-depth propagation and retention was investigated in pure quartz and kaolinite-bearing porous media. In both mineralogies, the resistance factor quickly stabilized when polymer was injected alone whereas injection of larger solution volumes was required to reach stabilization when surfactant was present. In pure quartz, polymer retention was shown, surprisingly, to be one order of magnitude higher in presence of surfactant whereas with kaolinite, surfactant did not impact polymer retention. The results can be interpreted by considering adsorption-governed retention. The mechanistic pictures being that (a) large polymer macromolecules are not able to penetrate the porosity of smectite aggregates, whereas surfactant molecules can, and (b) that surfactant and polymer mixed adsorbed layers can be formed on surfaces with limited affinity for polymer. Overall, this study shows that C-EOR can be applied in low permeability reservoirs but that successful injection strategies will strongly depend on mineralogy.
Chang, Hongli (University of Alaska Fairbanks) | Saravanan, Naresh (University of Alaska Fairbanks) | Cheng, Yaoze (University of Alaska Fairbanks) | Zhang, Yin (University of Alaska Fairbanks) | Dandekar, Abhijit (University of Alaska Fairbanks) | Patil, Shirish (King Fahd University of Petroleum and Minerals)
Abstract The formation of stable heavy oil emulsion, which may upset separation facilities and eventually lead to production impairment, is one of the most common issues encountered in the development of heavy oil reservoirs. This paper investigates the influence of various physicochemical parameters, including water cut, polymer status (sheared/unsheared), polymer concentration, demulsifier type and concentration, and the coexistence of polymer and demulsifiers on the stability of heavy oil emulsion. The viscosity of heavy oil emulsion is also studied at various water cut and polymer concentration. In this study, water-in-heavy oil emulsion was prepared at the water cut of 30% as the blank sample using heavy oil with API gravity of 14.5° and the synthetic brine. The effect of the water cut was investigated by both the bottle test method and multiple light scattering (MLS) method to validate the effectiveness and reliability of the MLS method. The other parameters were studied only through the MLS method. The results showed that the increasing water cut resulted in the decrease of heavy oil emulsion stability and could potentially invert the stable w/o emulsion to loose o/w emulsion at the phase inversion point where the emulsion viscosity peak occurred. Adding polymer, regardless of the polymer status, tended to reduce the stability of heavy oil emulsion, and the unsheared polymer contributed to less emulsion stability. However, the influence of polymer concentration was rather complicated. The emulsion stability decreased as polymer concentration increased, and further increasing polymer concentration enhanced the emulsion stability. A similar trend was also evidenced by emulsion viscosity with increasing polymer concentration. The addition of three oil-soluble emulsion breakers was able to break the heavy oil emulsion efficiently, whereas the water-soluble demulsifier had little demulsification effect. Furthermore, there existed an optimal concentration for the selected oil-soluble demulsifier to achieve the maximum separation. Although polymer itself could intensify the destabilization of heavy oil emulsion, it hindered the destabilization process of the heavy oil emulsion when the oil-soluble demulsifiers were added. This study will provide a comprehensive understanding of the factors affecting heavy oil emulsion stability.
von Gunten, Konstantin (University of Alberta) | Snihur, Katherine N. (University of Alberta) | McKay, Ryan T. (University of Alberta) | Serpe, Michael (University of Alberta) | Kenney, Janice P. L. (MacEwan University) | Alessi, Daniel S. (University of Alberta)
Summary Partially hydrolyzed polyacrylamide (PHPA) friction reducer was investigated in produced water from hydraulically fractured wells in the Duvernay and Montney Formations of western Canada. Produced water from systems that used nonencapsulated breaker had little residual solids (<0.3 g/L) and high degrees of hydrolysis, as shown by Fourier-transform infrared (FTIR) spectroscopy. Where an encapsulated breaker was used, more colloidal solids (1.1–2.2 g/L) were found with lower degrees of hydrolysis. In this system, the molecular weight (MW) of polymers was investigated, which decreased to <2% of the original weight within 1 hour of flowback. This was accompanied by slow hydrolysis and an increase in methine over methylene groups. Increased polymer-fragment concentrations were found to be correlated with a higher abundance of metal-carrying colloidal phases. This can lead to problems such as higher heavy-metal mobility in the case of produced-water spills and can cause membrane fouling during produced-water recycling and reuse.
Zaitoun, Alain (Poweltec) | Templier, Arnaud (Poweltec) | Bouillot, Jerome (Poweltec) | Salehi, Nazanin (Poweltec) | Wijaya, Budi Rivai (Pertamina PHE ONWJ) | Wijaya, Agung Arief (Pertamina PHE ONWJ) | Witjaksono, Arief (Pentraco) | Kurniadi, Wery (Pentraco)
Abstract Many fields in South East Asia are suffering from sand production problems due to sensitive sandstone formation. Sand production increases with time and increasing water production. The production of sand induces loss of production, due to sand accumulation in the wellbore, and heavy operational costs such as frequent sand cleaning jobs, pump replacements, replacement of surface and downhole equipment, etc. An original sand control technology consisting of polymers injection and already deployed in gas wells, has been successfully tested in an offshore oil well. The technology utilizes polymers having a natural tendency to coat the surface of the pores by a thin gel-like film of around 1 µm. Contrary to the use of resins which aim at creating a solid around the wellbore, the polymer system maintains the center of the pores fully open for fluid flow, thus preserving oil or gas permeability while often reducing water permeability (a property known as RPM for Relative Permeability Modification). The advantage of such system is that the product can be injected in the bullhead mode and often, a reduction of water production is observed along the drop in sand production. In gas wells, the treatment lasts around 4 years and can be renewed periodically. A lab work was undertaken to screen out a polymer product well suited to actual reservoir conditions. We conducted bulk tests to evaluate product interaction on reservoir sand samples, and corefloods to evaluate in-situ performances. Treatment volume and concentration were determined after lab test. One of "Oil Well" candidate is located in Arjuna Field, offshore Indonesia. Downhole conditions are: Temperature = 178°F, salinity = 18000 ppmTDS, permeability = 140-300mD, two perforated intervals with total thickness of 67ft (ft-MD) with 38 ft Average Netpay Thickness, production rate = 800 bfpd. The well is under gas lift and needed to be cleaned out every 3 months because of sand accumulation. Polymer treatment was performed in two stages (bottom, then upper interval). A total volume of 150 m3 of polymer solution was pumped. Immediately after treatment, sand cut dropped from 1% to almost 0%. This enabled increasing the drawdown from 32/64’’ choke to 40/64’’, keeping the production sand free and sustained with time. This field test confirms the feasibility of the original sand control polymer technology both in gas wells and in oil wells, which opens high possibilities in the future.
Chen, Huaxing (CNOOC Ltd., Tianjin Branch) | Wang, Yufei (CNOOC Ltd., Tianjin Branch) | Pang, Ming (CNOOC Ltd., Tianjin Branch) | Fang, Tao (CNOOC Ltd., Tianjin Branch) | Zhao, Shunchao (CNOOC Ltd., Tianjin Branch) | Wang, Zhiyuan (CNOOC Ltd., Tianjin Branch) | Zhou, Yugang (CNOOC Ltd., Tianjin Branch)
Abstract Since the field test of polymer flooding technology was carried out in the Bohai Oilfield in 2003, problems such as plugging of polymer-response wells have become increasingly worse, and conventional acidizing and plugging removal measures have had poor results. Therefore, this paper carries out research to provide a basis for effective plug removal in oil wells, to improve the productivity of polymer flooding oil wells. In this paper, the component analysis of the plug samples from the benefit injection wells in the field was carried out. The clogging mechanism was studied through X-ray diffraction, scanning electron microscopy, energy spectrum analysis, infrared spectroscopy, and chromatography, as well as through dynamic simulation evaluation of plugs and dynamic displacement experiments of long cores. Through simulation experiments, the clogging mechanism is clarified and the blockage radius range was obtained by various methods such as inverse effect of comprehensive measures, well test interpretation, and empirical formula calculation. The analysis results of the plugs show that the inorganic components of the plugs are calcium and magnesium carbonate scales, clay minerals and iron salt precipitation, and the organic components are the micelles formed by the crosslinking of trivalent metal ions. The greater the concentration of polymer produced, the greater the strength of calcium-magnesium scale aggregates and aluminum-iron-colloid elastomer, the greater the degree and depth of reservoir pore throat clogging, the larger the screen clogging area, which will even block the inlet of electric submersible pump. This will result in poor acidizing plugging effect and rapid decline in oil well productivity. Through various methods such as the inverse effect of comprehensive measures, well test interpretation, and empirical formula calculation, the blockage radius of polymer flooding response wells is greater than 4 meters. Based on this understanding, in the five wells plug removal measures, the unblocking radius and unblocking chemical agent system were adjusted and optimized. On-site application effect tracking shows that the plug removal measures have achieved good oil incremental effects, and the measures are all effective. Through the classification and comparison of oil well productivity characteristics, formation water composition, output polymer properties and other characteristics, this paper established the identification mark of plugging of polymer-response wells. In addition, an analysis method for clogging was established to clarify the composition and formation mechanism of the clogging. Finally, the plug radius calculation method was established by means of backstepping the effects of plug removal measures and well test interpretation analysis.
When cement is bullheaded into the annulus to displace mud, the differential pressure between the cement and the formation fluid can lead to a significant loss of cement filtrate into the formation. If, however, large volumes of cement filtrate invade the rock, the possibility of formation damage exists. Depending on the specific composition of the cement and its pH, the filtrate may be supersaturated with calcium carbonate and calcium sulfate. As the cement filtrate invades the formation and reacts with the formation minerals, its pH is reduced from 12 to a pH buffered by the formation minerals. This rapid change in pH can result in the formation of inorganic precipitates such calcium carbonate and calcium sulfate.