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Aften, Carl (SNF Holding Company) | Asgari, Yaser (SNF Holding Company) | Bailey, Lee (SNF Holding Company) | Middleton, Gene (SNF Holding Company) | Muhammed, Farag (SNF Holding Company) | Pageni, Parasmani (SNF Holding Company) | Sullivan, Keith (SNF Holding Company)
Abstract Friction reducer evaluations for field application selection are conducted in laboratory benchtop recirculating flow loops or once-through systems. Industry standard procedures and benchtop flow loop (loop) system specifications for friction reduction assessment are nonexistent, though standardization efforts are recently documented. Research and papers correlating friction reducer performance to brine and additives have been published, however other key variables can significantly affect performance and therefore must be addressed to maximize product recommendation accuracy. This paper illustrates how variances affect results. Benchtop recirculating loops used for testing friction reduction products for a specific field's application vary significantly in system components, configurations, and test analyses. Crucial loop system variance examples include differing pipe diameters, pump configurations, flow meter types and placement, differential pressure section and full run lengths, reservoir designs, mixing conditions, and end performance calculations. Oil and gas producers and service companies are trending towards outsourcing friction reducers to independent testing laboratories for loop assessment results prior to recommending friction reducers for end use field applications. These recommendations may have inherent selection bias depending upon the loop system's components and configuration. Friction reduction calculations during loop testing do not consistently consider changes in viscosity and temperature, thereby altering absolute results when evaluating performance. To apply the simplified assumptions in standard pressure, drop methodology, equivalency in flow rate, density, viscosity, and temperature within the run must be maintained. Performance of the friction reducer in a specific brine and additive test run should primarily be dependent upon dosage and method of injecting friction reducer into the loop, however other variables can contribute to performance results. We presume equivalency in pipe roughness and proper loop cleansing. The effects of these variables on friction reduction response applying wide-ranging factors of flowrate, density, viscosity, and temperature are evaluated using designed experiments with responses plotted and illustrated in Cartesian and contour graphs. The result of these designed experiments identified that certain variables are more influential on friction reducers’ measured performances in standard loop experiments and require observation and documentation during performance testing. The final study in this work generated vastly different performance curves when all of the aspects of loop design, entry and differential run lengths, flow rate, injection method, friction reducer types and loadings, and brine types, densities, viscosities, and temperatures were held constant. The goal of benchtop loop testing is scaling for actual field applications. Scaling discrepancies persist however due to differing pipe diameters, fluid circuit designs, and pump types and rates combined with changing brine compositions, proppant, and chemical additive effects on friction reducer products. Understanding that different benchtop loops, or potentially the same benchtop loop, will generate differing results is intriguing, yet unsettling.
Abstract Accurate and precise monitoring of chemical additives in oilfield brine is an important aspect of oil and gas operations towards corrosion control and flow assurance. Many operators are required to monitor the residual concentrations of chemical additives in production systems at specific locations to monitor and troubleshoot factors affecting chemical deliverability and performance. However, residual measurements are extremely problematic due to many factors, including the surface active nature of the chemicals and high ionic strength of the brine. The error on residual measurements can often be over 100%. Residual measurement typically requires the collection of a water sample, which often needs to be transported to a centralized analytical laboratory. Analytical techniques used to measure residuals are based on several combinations of separation (e.g. chromatography, liquid-liquid extraction, etc.) and detection (e.g. various forms of spectroscopy). However, most of these methods lack portability and require tedious laboratory procedures located off-site. The current paper describes a nanotechnology-enabled Raman spectroscopy method developed and tested for monitoring chemical inhibitor residuals. Development of this technology with handheld instrumentation provides better detection and quantification of chemical additives in the field and reduces time and cost compared to sending samples to off-site laboratories for data collection.
Abstract Critical micelle concentration (CMC) is a known indicator for surfactants such as corrosion inhibitors’ ability to partition to water from two phase systems such as oil and water. Most corrosion inhibitors are surface active. At critical micelle concentration, the chemical is partitioned to water from the interface, physisorption on metallic surfaces and forms a physical barrier between steel and corrosive water. This protective barrier thus prevents corrosion initiating on the metal surface. When the applied chemical concentration is equal or higher than the CMC, the surfactant is partitioned to aqueous phase from the oil-water interface. This would lead to higher chemical availability of the inhibitor in water, preventing corrosion. Therefore, it was suggested that CMC can be used as an indicator to optimal chemical dose for corrosion control1-5. The lower the CMC of a corrosion inhibitor product, the better is this chemical for corrosion control as the availability of the chemical in the aqueous phase increases. This can achieve corrosion control with lesser amount of corrosion inhibitor product. Thus, increasing the performance of corrosion inhibitor product. In this work, the physical property, CMC, was used as an indicator to differentiate corrosion inhibitor performance. A vast array of corrosion inhibitor formulations was achieved by combinatorial chemical methods using Design of Experiment (DoE) methodologies and these arrays of chemical formulations were screened by utilizing high throughput screening (HTE)6-8, using CMC as the selection guide. To validate the concept, a known corrosion inhibitor formulation (Inhibitor Abz) was selected to optimize its efficacy. This formula contains several active ingredients and a solvent package. Three raw materials of this formulation were selected and varied in combinatorial fashion, keeping the solvents and other raw materials constant9. These three raw materials were blended in a random but in a controled manner utizing DoE and using combinatorial techniques. Instead of rapidly blending a large amount of formulations using robotics, the design of experiment (DoE) methods were utilized to constrain the number of blends. When attempting to discover the important factors, DoE gives a powerful suite of statistical methodologies10. In this work, Design Expert software utilizes DoE methods and this prediction model was used to explore a desired design space. The more relevant (not entirely random) formulations were generated by DoE methods, using Design Expert software that can effectively explore a desired design space. The Design of Experiment software mathematically analyzes the space in which fundamental properties are being measured. The development of an equally robust prescreening analysis was also developed. After blending a vast array of formulations by using automated workstation, these products were screened for CMC by utilizing an automated surface tension workstation. Several formulations with lower CMCs than the reference product (Inhibitor Abz) were discovered and identified for further study. The selected corrosion inhibitor formulations were blended in larger scales. The efficacy of these products was tested by classical laboratory testing methods such as rotating cylinder electrode (RCE) and rotating cage autoclave (RCA) to determine their performance as anti-corrosion agents. As the focus of this project was to optimize the corrosion Inhibitor Abz, this chemical was used as the reference product throughout of this work. The testing indicated that several new corrosion inhibitor formulations discovered from this work outperformed the original blend, thus validating the proof of concept.
Azari, Vahid (Heriot-Watt University) | Rodrigues, Hydra (Heriot-Watt University) | Suieshova, Alina (Heriot-Watt University) | Vazquez, Oscar (Heriot-Watt University) | Mackay, Eric (Heriot-Watt University)
Abstract The objective of this study is to design a series of squeeze treatments for 20 years of production of a Brazilian pre-salt carbonate reservoir analogue, minimizing the cost of scale inhibition strategy. CO2-WAG (Water-Alternating-Gas) injection is implemented in the reservoir to increase oil recovery, but it may also increase the risk of scale deposition. Dissolution of CaCO3 as a consequence of pH decrease during the CO2 injection may result in a higher risk of calcium carbonate precipitation in the production system. The deposits may occur at any location from production bottom-hole to surface facilities. Squeeze treatment is thought to be the most efficient technique to prevent CaCO3 deposition in this reservoir. Therefore, the optimum WAG design for a quarter 5-spot model, with the maximum Net Present Value (NPV) and CO2 storage volume identified from a reservoir optimization process, was considered as the basis for optimizing the squeeze treatment strategy, and the results were compared with those for a base-case waterflooding scenario. Gradient Descent algorithm was used to identify the optimum squeeze lifetime duration for the total lifecycle. The main objective of squeeze strategy optimization is to identify the frequency and lifetime of treatments, resulting in the lowest possible expenditure to achieve water protection over the well's lifecycle. The simulation results for the WAG case showed that the scale window elongates over the last 10 years of production after water breakthrough in the production well. Different squeeze target lifetimes, ranging from 0.5 to 6 million bbl of produced water were considered to optimize the lifetime duration. The optimum squeeze lifetime was identified as being 2 million bbl of protected water, which was implemented for the subsequent squeeze treatments. Based on the water production rate and saturation ratio over time, the optimum chemical deployment plan was calculated. The optimization results showed that seven squeeze treatments were needed to protect the production well in the WAG scenario, while ten treatments were necessary in the waterflooding case, due to the higher water rate in the production window. The novelty of this approach is the ability to optimize a series of squeeze treatment designs for a long-term production period. It adds valuable information at the Front-End Engineering and Design (FEED) stage in a field, where scale control may have a significant impact on the field's economic viability.
Daeffler, Christopher (Schlumberger) | Fernandez del Valle, Julia (Schlumberger) | Elkhoury, Jean (Schlumberger) | Panga, Mohan (Schlumberger, Currently with ExxonMobil Integrated Solutions Company) | Nikolaev, Max (Schlumberger, Currently with CARBO) | Kamaletdinov, Bulat (Schlumberger)
Abstract Globally, dolomite formations are important reservoirs for oil and gas. Acid stimulation is commonly used to extend the life of carbonate reservoirs, and a good understanding of the fluid performance is essential for effective treatment design. Three acids, hydrochloric acid (HCl), emulsified HCl, and a single-phase retarded acid based on HCl, were assessed for their ability to create wormholes in Silurian dolomite under laboratory conditions using a standard core flow experiment. Select cores were imaged by X-ray computed tomography to visualize the wormhole morphology. Similar experiments in Indiana limestone was used as a control. The core flow experiments showed that the pore volume to break-through (PVbt) values for the retarded acids in Indiana limestone were less sensitive to changes in temperature overall than unmodified HCl. For Silurian dolomite though, the opposite is observed. HCl has uniformly high PVbt values at lower (200 °F) and higher (325 °F). The emulsified acid and the single-phase retarded acid are more efficient than HCl, but the difference is smaller at 325 °F. Core images revealed that all three fluids had some degree of wormhole branching at 200 °F and much less branching at 325 °F. By visual inspection, the single-phase retarded acid has less ramification than HCl and the emulsified acid. Overall, the results show that retarded acids should make effective stimulation fluids for dolomite reservoirs.
Mohr, Stephan (Nextmol, Bytelab Solutions SL) | Hoevelmann, Felix (Clariant Produkte, Deutschland GmbH) | Wylde, Jonathan (Clariant Oil Services, Clariant Corporation) | Schelero, Natascha (Clariant Produkte, Deutschland GmbH) | Sarria, Juan (Clariant Produkte, Deutschland GmbH) | Purkayastha, Nirupam (Clariant Produkte, Deutschland GmbH) | Ward, Zachary (Clariant Oil Services, Clariant Corporation) | Navarro Acero, Pablo (Nextmol, Bytelab Solutions SL) | Michalis, Vasileios K. (Barcelona Supercomputing Center)
Abstract Computational and experimental methods were employed to assess the capacity of four surfactant molecules to inhibit the agglomeration of sII hydrate particles. Using both steered and non-steered Molecular Dynamics (MD), the coalescence process of a hydrate slab and a water droplet, both covered with surfactant molecules, was computationally simulated. The experimental assessment was based on rocking cell measurements, determining the minimum effective dose necessary to inhibit agglomeration. Overall, the performance ranking obtained by the simulations and the experimental measurements agreed very well. Moreover, the simulations gave additional insights that are not directly accessible via experiments, such as an analysis of the mass density profiles or the orientations of the surfactant tails. The possibility to perform systematic computational high-throughput screenings of many molecules allows an efficient funnel approach for molecular optimization and customization.
Abstract Natural geochemical data, which refer to the natural ion concentration in produced water, contain important reservoir information, but is seldomly exploited. Some ions were used as conservative tracers to obtain better knowledge of reservoir. However, using only conservative ions can limit the application of geochemical data as most ions are nonconservative and can either interact with formation rock or react with other ions. Besides, mistakenly using nonconservative ion as being conservative may cause unexpected results. In order to further explore the nonconservative natural geochemical information, the interaction between ion and rock matrix is integrated into the reservoir simulator to describe the nonconservative ion transport in porous media. Boron, which is a promising nonconservative ion, is used to demonstrate the application of nonconservative ion. Based on the new model, the boron concentration data together with water production rate and oil production rate are assimilated through ensemble smoother multiple data assimilation (ES-MDA) algorithm to improve the reservoir model. Results indicate that including nonconservative ion data in the history matching process not only yield additional improvement in permeability field, but also can predict the distribution of clay content, which can promote the accuracy of using boron data to determine injection water breakthrough percentage. However, mistakenly regarding nonconservative ion being conservative in the history matching workflow can deteriorate the accuracy of reservoir model.
Abstract Over the last 30 years, chemical flooding of oil reservoirs has been broadly adopted as a technique for enhanced and incremental oil recovery around the world. Western Canadian oil producers have embraced polymer flooding to recover heavy oil, but have applied other forms of chemical flooding more sparingly. This study examines 31 chemical floods - ASP, AP, SP, alkali, and nanosurfactant floods - from mostly heavy oil fields (20 heavy oil, 10 medium oil, and one light oil). The success of the chemical floods was related to over forty reservoir and operating parameters, including water quality. We also discuss the operational challenges common in western Canada. Chemical flooding projects were identified through searches of government documents. Production and injection data were gathered using Accumap software; and reservoir and operating parameters were gathered from government documents and literature. Incremental recovery was calculated by performing decline curve analysis of the waterflooding production. The incremental recovery was the difference between the actual production during chemical flooding, and the predicted production had waterflooding continued rather than shifting to chemical flooding. Multivariate analysis was used to determine the most important parameters to the success of the chemical floods. The incremental recoveries ranged from 0 to 22% of original oil-in-place (OOIP), or 0 to 44% of OOIP per pore volume. Twenty-three of the 31 floods improved their water-oil ratios (WOR) after the start of chemical flooding. Water quality was a significant issue to the success of the chemical floods, leading to problems that were not anticipated in the planning and development stages. Some case histories are discussed to better illustrate the best practices for chemical recovery of heavy and medium oils. Water sources, management, treatment and chemistry all pose significant challenges that are often not fully assessed before starting the chemical flood projects. The review highlights challenges common to chemical flooding of heavy oil, and discusses common effects experienced as a result of water and chemistry compromises.
Abstract The goal of acid fracturing operations is to create enough fracture roughness through non-uniform acid etching on fracture surfaces such that the acid fracture can keep open and sustain a high enough acid fracture conductivity under the formation closure stress. A detailed description of the rough acid-fracture surfaces is required for accurately predicting the acid-fracture conductivity. In this paper, a 3D acid transport model was developed to compute the geometry of acid fracture for 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 the viscous fingering mechanism is commonly applied in acid fracturing to achieve non-uniform acid etching. Carbonate reservoirs mainly consists of calcite and dolomite minerals but the mineral distribution can be quite heterogeneous. Based on the developed model, we analyzed the effect of mineral heterogeneity on the acid etching process. We compared the acid etching patterns in different carbonate reservoirs with different spatial distributions of calcite and dolomite minerals. We found that thin acid-etched channels can form in carbonate reservoirs with interbedded dolomite layers. When the reservoir heterogeneity does not favor growing thin acid-etched channels, we investigated how to utilize the acid viscous fingering technique to achieve the channeling etching pattern in such reservoirs. Through numerical simulations, we found that thin acid-etched channels can form inside acid viscous fingers. The regions between viscous fingers are left less etched and act as barriers to separate acid-etched channels. In acid fracturing treatments with viscous fingering, the etching pattern is largely dependent on the perforation spacing. With a proper perforation design, we can still achieve the channeling etching pattern even when the reservoir does not have interbedded dolomite layers.
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