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polymer concentration
Tailor-Made Polymer Friction Reducers for Sustainable Development of Unconventional Oil & Gas Reservoirs
Giussi, Juan M. (YPF-TECNOLOGIA) | Dietrich, Roque (YPF-TECNOLOGIA) | Arias, Lila (YPF-TECNOLOGIA) | Rivelli, Sofia (YPF-TECNOLOGIA) | Martinez, Gerardo (YPF-TECNOLOGIA) | Romero, Juan Jose (YPF-TECNOLOGIA) | Medina, Rodrigo (YPF-NOC) | Bortolli, Eduardo (YPF-QUIMICA) | Lesbegueris, Juan (YPF-QUIMICA) | Vega, Isabel (YPF-TECNOLOGIA)
Abstract Today, Polymer Friction Reducers (PFRs) play a vital role in large displacement shale hydraulic fracturing. On one hand, PFRs reduce pipe frictional loss and enable a high pumping rate during fracturing and, on the other hand, PFRs transport the proppant throughout the procedure, avoiding premature settlement. As is well known, water-soluble polymers are sensitive to environmental conditions, salinity, temperature, pressure, and flow. Considering this situation, commercially available PFRs could present some problems if their universalization is pretended. The issues can be related to water solubility, salt tolerance, and reservoir conditions, among others. Taking into consideration the specific conditions of the reservoirs to implement PFRs and defined fracturing processes, this work shows as we develop novel PFRs that had, in Argentinian fields, good drag reduction performance and proppant transport. Using macromolecular design and synthesis, it was possible to obtain more than 100 novels PFRs. The synthetic approach in laboratory involved living radical polymerization techniques, employing specific tailor-thinking monomers to produce polymers that exhibited high-performance characteristics in rheologic behaviors and fluid dynamics, measured in a friction loop. A selected candidate was scaled up from 0,1 L to 30.000 L to carry out a field trail. The progressive scaling up of the technology was reproducible and the PFRs showed a stable rheological and drag reduction behavior. The field test was successful and allowed us to hydraulically stimulate Vaca Muerta for more than 4 hours, showing the designed and made in-house polymer, a very good performance. The capability to prepare tailor-made PFRs and implement them from the reactor directly in the field, without drying processes, encourages us to open a new play in the Argentinian development of unconventional reservoirs, more sustainable, cheaper, and sovereign. Introduction Shale oil and shale gas rank among the most significant fossil fuel resources worldwide. While their geological characteristics may vary, low permeability is a common parameter shared by these reservoirs. As a result, shale reservoirs often require extensive hydraulic stimulation treatments to achieve commercial productivity. High production levels can only be attained by establishing flow networks that connect artificial fractures, natural fractures, and the matrix. In this high-displacement mode, low sand concentration and a large fluid volume are used, leading to very high injection rates of fracturing fluid, reaching up to 120 barrels per minute.
- South America (0.47)
- North America > United States > Wyoming > Sweetwater County (0.24)
- North America > United States > Texas > Borden County (0.24)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.46)
Investigation of the Effect of Residual Oil and Wettability on Sulfonated Polymer Retention in Carbonate under High-Salinity Conditions
Alfazazi, Umar (Department of Chemical and Petroleum Engineering, Khalifa University of Science and Technology (KU)) | Chacko Thomas, Nithin (Department of Chemical and Petroleum Engineering, Khalifa University of Science and Technology (KU)) | Al-Shalabi, Emad Walid (Department of Chemical and Petroleum Engineering, Research and Innovation Center on CO2 and Hydrogen (RICH), Khalifa University of Science and Technology (KU) (Corresponding author)) | AlAmeri, Waleed (Department of Chemical and Petroleum Engineering, Research and Innovation Center on CO2 and Hydrogen (RICH), Khalifa University of Science and Technology (KU))
Summary Polymer flooding in carbonate reservoirs is greatly affected by polymer retention, which is mainly due to adsorption by polymer-rock surface interactions. Consequently, this leads to a delay in polymer front propagation and related oil recovery response. This work investigates the effects of residual oil (Sor) and wettability on sulfonated-based (ATBS) polymer retention under the conditions of high salinity and moderate temperature. Polymer single- and two-phase dynamic adsorption tests as well as bulk and in-situ rheological experiments were conducted on outcrop carbonate cores in the presence of a high-salinity brine of 243,000 ppm at a temperature of 50ยฐC. A total of four corefloods were conducted on Indiana limestone core samples with similar petrophysical properties. Overall, polymer adsorption was found to be low and within the acceptable range for application in carbonate reservoirs in the absence and presence of Sor. Furthermore, the polymer adsorption and in-situ rheology tests highlighted the significance of oil presence in the core samples, where retention was found to be around 40โ50 ยตg/g-rock and 25โ30 ยตg/g-rock in the absence and at Sor, respectively. An additional 50% reduction in retention was observed on the aged core sample that is more oil-wet. Polymer retention/adsorption was measured by double slug and mass balance techniques, and the results from both methods were in agreement with less than 7% difference. Inaccessible pore volume (IPV) was also calculated based on the double slug method and was found to be in the range of 23% to 28%, which was qualitatively supported by in-situ saturation monitoring obtained from an X-ray computed tomography (CT) scanner. The ATBS-based polymer showed excellent results for applications in carbonate without considerable polymer loss or plugging. This paper provides valuable insights into the impacts of residual oil and wettability on polymer adsorption, supported by CT in-situ saturation monitoring, which is necessary to avoid unrepresentative and inflated polymer retentions in oil reservoirs.
- South America (1.00)
- North America > United States > Texas (0.28)
- North America > United States > Indiana (0.25)
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (0.15)
- Geology > Geological Subdiscipline (0.48)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.34)
Effect of Residual Oil Saturation and Salinity on HPAM Rheology in Porous Media
Seright, R. S. (New Mexico Institute of Mining & Technology, Socorro, NM, USA) | Azad, Madhar Sahib (King Fahd University of Petroleum & Minerals, Dhahran, Saudi Arabia) | Abdullah, Mohammad B. (University of Texas at Austin, Austin, TX, USA) | Delshad, Mojdeh (University of Texas at Austin, Austin, TX, USA)
Abstract During polymer flooding, the velocities where shear-thickening occurs directly impact HPAM injectivity, fracture initiation, and whether viscoelasticity is significant in oil recovery. The onset velocity for shear-thickening in oil-free porous media is known to translate with the square root of permeability-porosity. However, few studies report HPAM rheology with residual oil present, and those conflict and are inconsistent with behavior seen without oil. This paper experimentally clarifies how Sor, salinity, and temperature impact HPAM rheology in rock. HPAM rheology at 20ยฐC was determined in Berea sandstone for Darcy velocities from 0.01 to 100 ft/d, Sor from zero to 0.55, and krw from 0.03 to 1. In a given experiment, the core was first exposed to the highest pressure-gradient for the test series. After stabilization, resistance factors were recorded and effluent viscosity was measured. Next, the velocity was halved, and the stabilization and measurement processes were repeated. This procedure was extended in steps to the lowest velocities. We also studied the effect of salinity on HPAM rheology in porous media between 0.105% to 10.5% TDS for 0.1% and 0.2% HPAM (at 20ยฐC). Temperature effects on rheology in Berea from 20ยฐC to 60ยฐC were investigated using 0.2% HPAM in 0.105%-TDS water. This work provides key information that will be crucial to establishing whether HPAM viscoelasticity can play a significant role in recovering oil in field polymer floods. It also provides crucial information for analytical/numerical efforts to establish when fractures will initiate and how far they will extend from the wellbore during polymer flooding field applications.
- Geology > Geological Subdiscipline > Geomechanics (0.66)
- Geology > Rock Type (0.49)
Mechanistic Modeling for Low Salinity Polymer (LSP) Flooding in Carbonates Under Harsh Conditions
Hassan, Anas M. (Petroleum Engineering Department, Khalifa University of Science and Technology, Abu Dhabi, UAE.) | Al-Shalabi, Emad W. (Petroleum Engineering Department, Khalifa University of Science and Technology, Abu Dhabi, UAE.) | Arellano, Aaron G. Tellez (Petroleum Engineering Department, Khalifa University of Science and Technology, Abu Dhabi, UAE.) | Kamal, Muhammad S. (College of Petroleum Engineering and Geosciences, King Fahad University of Petroleum and Minerals, Dhahran, KSA.) | Patil, Shirish (College of Petroleum Engineering and Geosciences, King Fahad University of Petroleum and Minerals, Dhahran, KSA.) | Hussain, Syed M. Shakil (College of Petroleum Engineering and Geosciences, King Fahad University of Petroleum and Minerals, Dhahran, KSA.)
Abstract Low Salinity Polymer (LSP) injection is a hybrid synergistic Enhanced Oil Recovery (EOR) technique that improves displacement efficiency by combining the advantages of both low salinity and polymer flooding methods. Nevertheless, proper design of this technique at field-scale requires a predictive mechanistic model that captures the geochemical interactions that occur within the polymer-brine-rock (PBR) system. A few studies have so far attempted to mechanically model the LSP injection process. Therefore, to achieve a realistic mechanistic model in this contribution, we used the validated coupled MRST-Iphreeqc simulator, which integrates the MATLAB Reservoir Simulation Toolbox (MRST) with IPhreeqc geochemical software, for gaining more knowledge about the geochemical interactions within the PBR system during LSP flooding. In particular, this study investigates the effect of water chemistry (salinity and hardness), rock-permeability, hydrolysis, and rock-mineralogy (dolomite and calcite) on polymer viscosity in carbonates under harsh conditions. In addition, charge ratio (CR) analysis was conducted for risk evaluation of polymer viscosity loss as a function of salinity, hardness, and rock mineralogy variations, and thus, the capacity of cation exchange during LSP injections was examined. The outcome of this study shows that the LSP solutions demonstrated higher divalent cation (Ca + Mg) concentrations than the produced fluids of the LS injections with no polymer. The scenario of twice spiked salinity (1246 ppm) is more beneficial than the twice diluted salinity (311.5 ppm), as per their corresponding polymer viscosity losses of 35% and 72%, respectively. For the dolomite model, the 10-times spiked hardness was found to be superior to the hardness case of 10-times diluted, as per their corresponding polymer viscosity losses of 30% and 60%, respectively. For the calcite model, the 10-times spiked hardness was found to be more preferable than the 10-times diluted hardness, as per their corresponding polymer viscosity losses of 26% and 53%, respectively. Therefore, in terms of reducing polymer viscosity loss, calcite model was the most advantageous rock-forming mineral. For LSP injection de-risking strategies, the impact of the divalent cation was associated with the CR value. Thus, it is necessary to obtain a CR value that is ideal and at which the viscosity loss is minimal. According to the CR calculations, a CR > 1 indicates minimal viscosity loss in the LSP-solution, which correlates to the cation threshold concentration of 130 ppm. The LSP solution is anticipated to undergo considerable viscosity loss at CR < 0.5. Additional risk evaluation for viscosity loss would be required when 0.5 < CR < 1. Accordingly, to optimize the LSP process in carbonates, careful design of the divalent cations (Ca + Mg) is essential, as it can affect the LSP solution viscosity. Hence, the benefit of this study includes providing consistent data for further research into optimizing the LSP injection strategy.
- Asia > Middle East (1.00)
- North America > United States > Texas (0.46)
- Research Report > New Finding (0.86)
- Research Report > Experimental Study (0.68)
- Geology > Geological Subdiscipline > Geochemistry (0.89)
- Geology > Mineral > Carbonate Mineral > Calcite (0.67)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Dolomite (0.47)
Production Enhancement of Heavy Oil Reservoir at South of Sultanate of Oman Salt Basin with Implementation of Design and Data Diagnostic Cycle of Hydraulic Fracturing Campaign
Kindi, O. (Petroleum Development Oman) | Al Riyami, S. (Petroleum Development Oman) | Hinai, S. (Petroleum Development Oman) | Al Busaidi, A. (Petroleum Development Oman) | Al Mukhaini, S. (Petroleum Development Oman) | Hashmi, M. (Petroleum Development Oman) | Sayed, M. (Petroleum Development Oman) | Konwar, A. (Petroleum Development Oman) | Christiawan, A. B. (Abraj Energy Services, Muscat Oman) | Yuyan, R. (Abraj Energy Services, Muscat Oman)
Abstract At South of the Sultanate of Oman Salt Basin province, with multiple oilfield cluster such as Asset M, Asset N, and Asset B, the production enhancement method with hydraulic fracturing stimulation technique has grown from just merely 5 treatments on trial basis till 2017 to be favorable completion and production enhancement method with over 20 fracture treatments annually in 2020 onwards. The basin is predominantly oil reservoir came from Cambro-Ordovician and Carboniforous-Permian era layers, which consist of various sandstone reservoir such as Reservoir H family, Reservoir G family and Reservoir K. Typical characteristic of the Reservoir H within Asset M cluster is relatively shallow depth layer high permeability rock with low current reservoir pressure due to depletion lowering its lithostatic stress value, nevertheless some area in the vicinity of faults are tectonically loaded resulting to formation stress complexity that complicate the process of hydraulic propped fracturing. This fault rich region and close spacing of offset producer and injector wells are major geo-hazards that warrant controlled fracture geometry. In addition, the reservoir fluids properties contribute to further challenges with some area infamously produced high viscous heavy oil that altering the reservoir transmissibility hence the leak off behavior during fracture treatment, also later production period prone to wax and emulsion problems. Both the original formation water and injected water breakthrough from nearby injector wells are prone to scale precipitation that restrict hydrocarbon flow in reservoir and tubular. New method of calculating reduced pad volume percentage to lower post fracture polymer concentration impact and or to achieve Tip Screen Out fracture placement has been implemented in several treatments. The reduction on fracturing fluid polymer gel fluid concentration (gel loading) has also been implemented on this campaign, resulting in better flowback clean-up process. Scale precipitation study and available inhibition techniques has been evaluated for future strategy. Proppant flowback control were known issues post fracture treatment, study on several proppant flowback control techniques has been done, as the outcome the utilization of self-consolidated proppant tailed-in will be implemented on future treatment. This paper illustrates the continuous study and meticulous planning of design execution process of hydraulic propped fracturing, offering resolution to multiple challenges as mentioned earlier. Several strategies have been successfully implemented as part of the resolution, while some of the techniques are planned to be deployed in the future as part of continuous learning curve. The general outline of the methodology cycle can be viewed on figure 1 below. The scope of hydraulic propped fracturing campaign is covering both oil producer wells and water injector wells within South Sultanate of Oman Salt Basin to Central platform. Figure 1: Design Deployment and Diagnostic Methodology Cycle
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.69)
Summary At the Milne Point polymer flood (North Slope of Alaska), polymer retention is dominated by the clay, illite. Illite, and kaolinite cause no delay in polymer propagation in Milne Point core material, but they reduce the effective polymer concentration and viscosity by a significant amount (e.g., 30%), thus reducing the efficiency of oil displacement until the full injected polymer concentration is regained [which requires several pore volumes (PVs) of throughput]. This work demonstrates that polymer retention on illite is not sensitive to monovalent ion concentration, but it increases significantly with increased divalent cation concentration. The incorporation of a small percentage of acrylamido tertiary butyl sulfonic acid (ATBS) monomers into hydrolyzed polyacrylamide (HPAM) polymers is shown to dramatically reduce retention. The results are discussed in context with previous literature reports. Bridging adsorption was proposed as a viable mechanism to explain our results. Interestingly, an extensive literature review reveals that polymer retention (on sands and sandstones) is typically only modestly sensitive to the presence of oil. Extensive examination of the literature on inaccessible pore volume (IAPV) suggests the parameter was commonly substantially overestimated, especially in rock/sand more permeable than 500 md (which comprises the vast majority of existing field polymer floods).
- Asia > Middle East (1.00)
- North America > United States > Texas (0.68)
- South America > Suriname > North Atlantic Ocean > Guyana-Suriname Basin > Tambaredjo Field (0.99)
- South America > Guyana > North Atlantic Ocean > Guyana-Suriname Basin > Tambaredjo Field (0.99)
- Asia > Kazakhstan > Mangystau Oblast > Caspian Sea > Precaspian Basin > Kalamkas-More Field > Kalamkas Field (0.99)
- (5 more...)
Comparison of Different Methods to Evaluate the Effect of Temperature on Polymer Retention and Degradation in the Presence and Absence of Oil on Carbonate Outcrops
Sebastian, Anoo (Chemical and Petroleum Engineering Department, Khalifa University of Science and Technology, Abu Dhabi, UAE.) | Musthaq, Muhammad (Chemical and Petroleum Engineering Department, Khalifa University of Science and Technology, Abu Dhabi, UAE.) | Al-Shalabi, Emad W. (Chemical and Petroleum Engineering Department, Research and Innovation Center on CO2 and Hydrogen, Khalifa University of Science and Technology, UAE.) | AlAmeri, Waleed (Chemical and Petroleum Engineering Department, Research and Innovation Center on CO2 and Hydrogen, Khalifa University of Science and Technology, UAE.) | Mohanty, Kishore (Hildebrand Department of Petroleum and Geosystems Engineering, The University of Texas at Austin, USA.) | Masalmeh, Shehadeh (Abu Dhabi National Oil Company โ Upstream, UAE.) | AlSumaiti, Ali M. (Abu Dhabi National Oil Company โ Upstream, UAE.)
Abstract Polymer retention poses a significant challenge in polymer flooding applications, emphasizing the importance of accurately determining retention levels for successful project design. In carbonate reservoirs of the Middle East, where temperatures exceed 90 ยฐC, conducting adsorption tests under similar temperature conditions becomes crucial for the precise determination of adsorption values. The choice of analytical method heavily impacts the accuracy of retention measurements from effluent analysis. This study investigates the effect of temperature on the performance of a polymer, specifically its rheological behavior and retention. Rheological and polymer flooding experiments were carried out using an ATBS-based polymer in formation water (167,114 ppm) at different temperatures (25, 60, and 90 ยฐC) with required oxygen control measures. Dynamic polymer retention was conducted in both absence of oil (single-phase tests) and presence of oil (two-phase tests). In addition, different analytical techniques were evaluated, including viscosity measurements, UV-visible spectroscopy, and TOC-TN analysis, to determine the most accurate method for measuring the polymer concentration with the least associated uncertainty. Furthermore, the study investigates the effects of these uncertainties on the final dynamic polymer retention values by applying propagation of error theory. The effluent polymer concentration was determined using viscosity correlation, UV spectrometry, and TOC-TN analysis, all of which were reliable methods with coefficient of determination (R) values of โผ0.99. The study analyzed the effects of flow through porous media and back-pressure regulator on polymer degradation. The results showed that the degradation rates were around 2% for flow through porous media and 16% for mechanical degradation due to the back-pressure regulator for all temperature conditions. For the effluent sample, the concentration of effluents was lower when using the viscosity method due to polymer degradation. However, the TOC-TN and UV methods were unaffected as they measured the total nitrogen and absorbance at a specific wavelength, respectively. Therefore, all viscosity results were corrected for polymer degradation effects in all tests. During 60 ยฐC single-phase studies, the dynamic retention values obtained from viscosity correlation, UV spectrometry, and TOC-TN analysis were determined to be 52 ยฑ 3, 45 ยฑ 5, and 48 ยฑ 3 ฮผg/g-rock, respectively. During the two-phase coreflooding experiment conducted at 25 ยฐC, the accuracy of the UV spectrometry and viscosity measurements were affected by the presence of oil, rendering these methods unsuitable. However, the TOC-TN measurements were able to deliver a retention of 24ยฑ 3 ฮผg/g-rock. Moreover, the use of glycerine preflush to inhibit oil production during polymer injection in the two-phase studies showed that all three methods were appropriate with dynamic retention values of 27ยฑ 3, 25ยฑ5, and 21ยฑ3 ฮผg/g-rock for viscosity, UV, and TOC-TN, respectively at 60 ยฐC. The error range was obtained using the propagation of error theory for all the methods. Accordingly, it was also noted that the temperature did not affect the dynamic retention values in both single-phase and two-phase conditions. The dynamic retention values for single-phase using the UV method and two-phase using the TOC-TN method were 45 โ 56 ยฑ5 ฮผg/g-rock and 21 โ 26 ยฑ3ฮผg/g-rock, respectively, for the range of temperatures applied. The findings of this study highlight that when adequate oxygen control measures are implemented, the temperature does not exhibit a statistically significant impact on the retention of the ATBS-based polymer under investigation. Furthermore, TOC-TN has been identified as the optimal analytical method due to its minimal uncertainties and ease of measuring polymer concentration under varying experimental conditions.
- North America > United States > Texas (0.46)
- North America > United States > Oklahoma (0.28)
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (0.17)
A State-of-the-Art Water Shutoff System in Carbonate Reservoir: From Lab to Field
Alabdrabalnabi, M. I. (Saudi Aramco PE&D, Dhahran, Saudi Arabia) | Almohsin, A. M. (Saudi Aramco PE&D, Dhahran, Saudi Arabia) | Baiz, A. I. (Saudi Aramco PE&D, Dhahran, Saudi Arabia) | Busaleh, A. S. (Saudi Aramco PE&D, Dhahran, Saudi Arabia) | Al Bin Saad, H. (TAQA Well Solutions, Dhahran, Saudi Arabia)
Abstract Polymer gel systems have been utilized extensively as a water shutoff material to control and reduce excessive water production and eventually improve oil recovery. A novel water shutoff material with excellent gel strength and thermal stability has been developed to minimize water production zones based on various operational parameters such as pressure, temperature, pumping rate, treatment duration, and shut-in time. This paper presents the state of art polymer gel with an adsorption system from the laboratory phase to the thriving field implementation of water shutoff technology in carbonate formation. The developed polymer gel system comprises copolymer, organic crosslinker, and adsorption constituents. The water shutoff agent's gel strength and gelation time were deeply examined using high-pressure, high-temperature (HPHT) rheometers. The rheological properties, such as storage modulus (Gโ) and loss modulus (G") of matured gels with different compositions, were studied to identify the gel strength of each system. Additionally, the effect of temperature, polymer, and crosslinker on the gelation reaction was captured as part of the experimental research. Based on extensive lab experiments at downhole reservoir conditions, the water shutoff treatment was optimized to control water production from vertical oil well producers. The experimental results indicated that this water shutoff technology exhibited low initial viscosity for all systems below 20 cP at standard conditions, giving an advantage of pumping requirements during fluid mixing and injection to the targeted zones in the field execution. Once the water shutoff fluid travels downhole to the targeted zone, the temperature starts to buildup, and the gelation reaction begins. Consequently, the fluid viscosity is controlled at a specific bottomhole temperature based on liquid compositions, mainly polymer, crosslinker, and adsorption agents. This determines the gelation time between minutes to more than 10 hours. Therefore, this water shutoff gel can be placed smoothly into the target zone as a single-phase fluid with desired gelling time to plug the targeted formation. As for treatment design, the field testing utilized an E-coil string to run a production logging tool to spot the sources of water production and detect the bottomhole temperature and pressures essential to formulate the water shutoff system. The post-treatment flowback revealed promising results of this novel polymer gel system. The water shutoff fluid minimizes more than 60% of water production based on pre-treatment flowback. The newly developed water shutoff system is a promising polymer gel technology to control water production from carbonate oil formations. The experimental findings and field outcomes unveiled that this robust polymer gel efficiently plugged the water zone at high temperature and pressure conditions.
- North America > United States (1.00)
- Asia > Middle East > Saudi Arabia (0.47)
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.34)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Production and Well Operations > Well Operations and Optimization > Produced water management and control (1.00)
- Production and Well Operations > Well Intervention > Water shut-off (1.00)
Abstract Polyacrylamide polymer flooding is an established EOR technique to reduce the water/oil mobility ratio and improve sweep efficiency. Polyacrylamide polymers are non-Newtonian fluids whose viscosity depends significantly on shear rate in addition to several other parameters, such as brine salinity and hardness, temperature, polymer concentration, chemical composition, and molecular weight. Each oil reservoir has unique brine compositions, expected shear, and temperature conditions. Estimating the polymer solution's in situ viscosity under these conditions can be quite challenging, requiring expensive and time-consuming rheological lab experiments. Machine learning has recently gained popularity and has been applied successfully in many sectors, including the oil & gas industry, to develop predictive models and forecasting tools. With more than 30 years of experience in polymer EOR projects globally, SNF has compiled a large rheological dataset, including approximately 75,000 lab experiments measuring the viscosity of its synthetic polymers under different reservoir conditions. In this study, different machine learning algorithms have been tested on SNF's rheological dataset to predict polymer viscosity for any given polymer type and concentration under certain reservoir conditions. The best results were achieved using a Random Forest algorithm, the results of which have been presented here. The model predictions are based on the following eight input features: active polymer concentration, shear rates, brine total dissolved solids (TDS), hardness, temperature, polymer molecular weight, and chemistry (ATBS percentage and Acrylamide percentage). Based on preliminary investigations, the results obtained are promising, with an R-Squared regression score of 89.6 % and a mean absolute percentage error of 35.8%. The model's results have helped SNF better understand the impact of these different parameters on polymer viscosity and can be used for improved quality control of lab measurements generated across the globe. This tool aims to aid product development by providing in silico data in concurrence with in situ experiments, driving a robust development process.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.34)
Abstract Back-produced polymer to surface facilities is a significant topic in the literature due to the specific properties of the polymer, which are beneficial in the effective displacement of oil in the reservoir but could give challenges in the producers and surface facilities. This literature review addresses the impact of polymer on the key components of the production facilities ranging from artificial lift to the oil refinery and produced water disposal or reuse. The main polymer properties to interfere are (1) the ability to increase the viscosity of the produced water and (2) the precipitation of the polymer with constituents in water or process chemicals. These two properties could cause equipment failure, off spec quality of the oil and water, leading to oil deferment and increased maintenance. The magnitude of these challenges depends on the level of back-produced polymer. From the literature it is difficult to diagnose at what polymer concentration, insignificant impact is observed and when the production issues begin. It is recommended to analyse each key component individually and assess at what polymer concentration impact is expected in the operations. Important to identify is that an optimal polymer selection for the subsurface reservoir, might not be the right choice for the production facility. Therefore, early involvement of surface and chemical engineers is crucial to a successful polymer flood. This review will discuss a selection of the available literature addressing the main challenges and showing several examples. The content of a monitoring plan is discussed as well as the critical & additional analysis are given to properly understand the production side of a polymer flood and assist with mitigation strategies.
- Asia > Middle East (1.00)
- Europe > Austria (0.93)
- North America > United States > Texas (0.68)
- Asia > China > Heilongjiang Province (0.46)
- Research Report > New Finding (0.93)
- Overview (0.68)
- Geology > Mineral (0.67)
- Geology > Geological Subdiscipline (0.46)
- Water & Waste Management > Water Management > Lifecycle > Treatment (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > Canada > Alberta > Flood Field > Adamant Masters Flood 6-6-85-24 Well (0.99)
- Europe > Austria > Vienna > Vienna Basin (0.99)
- Europe > Austria > Vienna Basin > Matzen Field (0.99)
- (8 more...)