|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
Total dissolved solids in a quantity of liquid. Mineral material suspended or dissolved in solution which passes a standard glass filter and 0.45 1-1m filter and does not evaporate below 180 C. TDS is generally used as a gross indicator of the mass of dissolved salts in a solution, but the analytical method is subject to interferences from colloidal material. Total dissolved solids in a quantity of liquid. Mineral material suspended or dissolved in solution which passes a standard glass filter and 0.45 1-1m filter and does not evaporate below 180 C. TDS is generally used as a gross indicator of the mass of dissolved salts in a solution, but the analytical method is subject to interferences from colloidal material.
Innovation in oil extraction, particularly around water, has made the concept of "peak oil" a distant memory. New extraction methods propelling the future of oil and gas depend heavily on water as a critical input--shale developments and waterflood enhanced oil recovery (EOR) are two examples. Extraction using water has opened up substantial new hydrocarbon resource plays. However they can produce four times more salty water byproduct than oil. Operators have become experts at reusing this water, in some cases over 95% of it.
Miralles, Vincent (Solvay) | Marlière, Claire (IFP Energies Nouvelles) | Morgand, Claire (IFP Energies Nouvelles) | Rome, Virginie (IFP Energies Nouvelles) | Morvan, Mikel (Solvay) | Courtaud, Tiphaine (Solvay)
The purpose of surfactant-polymer (SP) formulation design is to concurrently achieve ultra-low interfacial tension and good mobility ratio. To this respect, associative polymers were found to be particularly interesting since their use could simultaneously solve demixing issues that can be observed in bulk when mixing surfactants with standard partially hydrolyzed poly-acrylamide (HPAM) polymers, and enhance the mobility ratio when injected in confined and under flow conditions.
Varying the brine salinity and the polymer chemistry (either HPAM or associative polymer) with the same surfactant system led to the definition of four SP compatibility cases, on the basis of phase diagrams. First the focus was specifically directed to bulk and kinetic studies based on viscosity, cryo-TEM and turbidity versus time measurements. Then, monophasic injections were performed in a coreflood rig with a 3D outcrop rock with the designed formulations. The mobility reduction entailed by the injected solutions was measured by monitoring the pressure drop along the core.
With the HPAM polymer, an increase in salinity leads to a clear degradation of the SP compatibility or even to a demixing behavior after a couple of days, due to depletion interactions. Interestingly, when the same surfactant system is mixed with the associative polymer, the demixing behavior vanishes due to a synergetic interaction between the surfactant and the associative polymer, hence changing the overall physical structure of the SP system and leading to a crystal clear formulation.
Regarding monophasic injections in coreflood, as expected the compatible SP formulations designed at low salinity led to excellent in-depth transport properties with both polymers. While demixing at high salinity, the SP formulation involving HPAM showed good transport properties since the mobility reduction stabilizes at a value close to the relative viscosity of the solution. More interestingly, the mobility reduction for the SP formulation integrating the associative polymer also reaches a plateau but with a value almost five times higher than its relative viscosity. These results highlight that the use of an associative polymer instead of a conventional HPAM in a SP formulation can present the double advantage of vanishing depletion interactions in bulk, hence improving the formulation's solubility, and enhancing the developed mobility reduction in a coreflood experiment.
It has been proven that associative polymers can bring a solution to SP compatibility issues by vanishing depletion interactions and hence improving the formulation's solubility. Depending on the surfactant formulation involved, the addition of an associative polymer can drastically enhance the developed mobility reduction while decreasing the polymer concentration compared to the use of a conventional HPAM polymer. This dosage reduction is also an element of economic advantage in favor of associative polymers.
Abstract Understanding water-rock interactions occurring during hydraulic fracturing is vital to better engineer the hydraulic fracturing water. In this study, a systematic model of water-rock reactions is presented to mimic the interaction of reservoir rock with water. To investigate the water-rock interaction Marcellus Formation was selected. The reservoir rock samples from the Marcellus Formation were first characterized for its mineral composition by an X-ray diffraction (XRD) and for its elemental composition by an X-Ray fluorescence (XRF). Based on XRD results 3 major minerals were found in Marcellus shale; quartz, calcite, and illite. Later, these minerals with high purity content were ordered from an external chemical company to prepare pseudo rock samples and single-, two-, and three- component mineral-deionized water systems were prepared. The supernatant of these solutions were analyzed for their pH, total dissolved solids (TDS) content, particle size of the colloidal system, and zeta potential of the colloidal systems. For single-component mineral-water systems, it has been observed that pH and TDS in general give a linear relation with the mineral concentration. For two component mineral-water systems, these relations got weaker and for the three-component systems, only TDS gives good linear relation to the mineral concentration at room temperature. When the experiments repeated at 75 °C to see the effect of temperature on dissolution of minerals in a single-component system, no difference was observed in the linear relations, however, it has been observed that particle sizes of the colloidal systems for all single-component mineral-water system correlates with the TDS content of the water. It should be noted that while particle sizes measure in water gives an idea of the average size of the suspended particles in water, TDS provides information on the dissolved molecules or ionized particles in water. Moreover, we observed that for all experimental data regardless the temperature that we collected them, the TDS concentration decreases with the increase in pH. Our results for the first time link dissolved matter concentration in water (TDS) with the colloidal system parameter (particle size) and provide an insight on how the colloidal system (suspended solids in water) can affect TDS concentration.
Produced or fresh water being treated may have suspended solids, such as formation sand, rust from piping and vessels, and scale particles, or dissolved solids (various chemical ions). For most uses or disposal methods, these solids may need to be removed. It may be necessary to remove these solids to prevent wear in high-velocity areas, prevent solids from filling up vessels and piping and interfering with instruments, and comply with discharge restrictions on oil-coated solids. This page discusses appropriate removal technologies and handling of the removed material. Solid particles, because of their heavier density (compared to water) and net negative buoyant force, will settle to the bottom with a terminal velocity that can be derived from Stokes' law, as shown in Eq. 1. This equation applies strictly to creeping flow regimes in which the Reynolds number is less than unity; this is mainly concerned with spheres of very small diameter surrounded by a liquid. For very small particles, the inertial forces are much less than the viscous forces because of the low particle mass, and the particle does not enter into a turbulent settling regime. Most sedimentation basins are rectangular flumes with length-to-width ratios of 4:1 or greater to limit crossflow.
A novel approach to provide a real-time, qualitative analysis of the effects of dynamically changing produced water chemistries on friction reduction through the use of water quality parameters including total dissolved solids (TDS), oxidation reduction potential (ORP), pH, and friction pressure.
The method employs the use of a suite of analytical sensors including a toroidal conductivity probe, combination pH/ORP probe, and pressure sensors. Slipstreams are taken from both before and after the blender and sent through the analytic suite to evaluate not only shifts in source water chemistry but also the effects of different chemical applications on the system. The drop across the system, when compared to a freshwater baseline, gives a qualitative estimate as to the friction reduction achieved by the fluid system.
Case studies on over 36 wells have been performed across various basins in the United States using both cationic and anionic friction reducers. Dynamically changing produced water blends and additive dosage and choice were the primary contributors to fluid system underperformance. Specifically, a lowered friction reduction efficacy was noticed when pumping at TDS levels between 20,000 - 80,000 ppm dependent on the choice of the friction reducer. This method was also highly effective in diagnosing and solving operational problems, such as acid leaks and proper chemical dosing. These findings were verified by the analytical sensor suite and confirmed by an increase in surface pressure and hydraulic horsepower utilized throughout the fracturing job. Utilizing this method allows for real-time, on-site differentiation between pressure anomalies caused by the fluid system compared with formation issues, as well as isolating the specific cause of fluid system performance issues.
This new analysis gives on-site personnel real-time insight into how dynamically changing fluid system chemistries impact friction reduction efficacy.
Slickwater fracturing operations using produced water have become more common in hydraulic fracture treatments. Lab testing prior to any job for water source quality is vital to ensure chemical compatibility of the fluid system, however, there is a lack of real-time testing methods available on-site as the water chemistry shifts throughout a job. Water pH, TDS, and ion content can vary significantly throughout a hydraulic fracturing job when using produced water. A wide variety of commercially available friction reducers allow for careful selection of the chemical based on friction reduction capability in the supplied water source TDS range. A produced water system typically includes dissolved solids, hydrocarbons, dissolved gasses and production chemicals prior to treatment. Various treatment stages are required to remove oil droplets, particulates and solids, depending on the water source quality to meet the regulatory requirements prior to arrival on a frac site (Shen et. al, 2019). The design and process of these treatment stages can cause variation based on operator and produced water source within the same geological region. Additional pretreatment methods, such as the addition of chlorine dioxide, microcellar biocides and peracetic acid may be used to kill bacteria present in the water prior to arrival on location, adjusting the overall chemical profile that the friction reducer must be compatible.
Oilfield Service companies face significant capital expenditures due to iron failures caused by corrosion, with variations in source water chemistry, fluid system additives and operational issues greatly impacting the frequency of these failures. This paper looks in depth at the root fluid system cause of corrosion in frac iron strings for different water sources in the Permian and Appalachian basins. The objective of this study is to determine the most common causes of corrosion between the two regions and determine which type of remediation technique is best suited for the conditions seen in each basin.
A suite of sensors was connected to the suction and discharge pumps of the blender in order to measure pH, conductivity, ORP, dissolved oxygen and corrosion values on the clean and slurry flow streams during the fracturing process. Treatment designs utilizing both slickwater and hybrid fluid systems were observed, with various buffers and corrosion inhibitors pumped as a corrosion control additive. Data was then analyzed based on basin, water quality and frac fluid chemistries to determine the root cause of corrosion and effectiveness of remediation methods.
The results of this study showed that the corrosion values vary significantly between the Appalachian and Permian basin due to the differences in source water quality. When utilizing produced or a blend of produced and fresh water, the Appalachian basin showed significantly higher corrosion due to higher TDS and lower pH ranges seen in the source water. The primary cause of corrosion was determined to be low pH levels in the fluid system, with buffer additives resulting in a 30% drop in general corrosion across a pad. For freshwater systems, the primary cause of corrosion was found to be increases in dissolved oxygen, with spikes in dissolved oxygen leading to a 40% increase in corrosion during certain key times in the operation. Significantly lower levels of corrosion were seen during freshwater treatments compared to produced water systems, with the primary cause of high-corrosion events due to operational introduction of oxygen into the system. Low pH fluid such as acid and varying temperature of the fluid system had significant impacts in corrosion for both fresh and produced water systems.
Utilizing real-time monitoring of dynamically changing frac fluid chemistries allows for selection of the most effective remediation method for reducing fluid corrosion in frac iron strings. This paper presents the results of the corrosion measurements of fluid systems seen across the Permian and Appalachian basins and identifies the most common root cause of corrosion in those regions.
Tomomewo, O. S. (University of North Dakota) | Dyrstad-Cincotta, N. (University of North Dakota) | Mann, D. (University of North Dakota) | Ellafi, A. (University of North Dakota) | Alamooti, M. (University of North Dakota) | Srinivasachar, S. (Envergex LLC) | Nelson, T. (Envergex LLC)
ABSTRACT The recent global expansion in the development of unconventional oil and gas assets has also resulted in a tremendous increase in the number of extended horizontal drilling and hydraulic fracturing projects in the Bakken. The United States is presently the largest global crude oil producer, and the Bakken Formation in North Dakota is one of the major contributors to this achievement. However, the wastewater produced from these increased oilfield activities are highly saline (∼170,000 to 350,000 ppm TDS) and no technology currently available can satisfactorily treat it. As a result, more than 90% of wastewater in the Bakken is disposed of by deep injection into disposal wells. However, there are growing environmental and operational concerns about the sustainability and impacts of this approach. Research has shown that cumulative wastewater injection in some areas could increase the chances of earthquakes in those areas. However, if this produced water is efficiently treated, it could be reused in hydraulic fracturing operations or to support coal mining and irrigation activities. All these applications would reduce the need for wastewater injection and reduce the demand for fresh water used in hydraulic fracturing operations across North Dakota. For this purpose, we propose an enhanced supercritical technology we call Supercritical Water Extraction – Enhance Targeted Recovery to handle the issue of high TDS of flowback and produced water in the Bakken. 1. INTRODUCTION Oil production from unconventional reservoirs, such as the Bakken, has become very important and their optimal development has been studied in detail worldwide, especially in North America. This is because, over the past few years, unconventional reservoirs have substantially added to the national reserves of the US hydrocarbon resources. Recently the United States has become self-sufficient in hydrocarbon needs, a feat it has been trying to achieve for many decades. The United States did not only stop the importation of crude oil but was also willing to export and add crude oil export as part of the source of revenue generating streams. The Bakken Formation is contributing immensely to this feat. In 2019, oil production from the top 10 Bakken producers rose to 176,603,000bbl from 13,500 producing wells at an average of 3142bbl/month from each well (North American Shale Magazine, 2020). For maximum primary oil recovery, between 60,000 to 80,000 wells must be drilled in all the oil producing counties in the Bakken; it is projected that this cannot be achieved until 2025 (North American Shale Magazine, 2020). However, with the current trend in drilling and completions technologies, the projected time may be shortened because the advancement in both the horizontal drilling and hydraulic fracturing technologies (Kolawole et. al., 2019a; Wigwe et. al., 2019a) in recent years has made it easy and has also reduced the time it usually takes to drill wells in the Bakken. The good thing is that there is a great reduction in both the drilling and completions cost (Wigwe et al., 2019b). However, as with every technological advancement, there are some problems.
Summary Reuse of flowback water in hydraulic fracturing is usually used by industry to reduce consumption, transportation, and disposal cost of water. However, because of complex interactions between injected water and reservoir rocks, induced fractures may be blocked by impurities carried by flowback and mineral precipitation by water/rock interactions, which causes formation damage. Therefore, knowledge of flowback water/rock interactions is important to understand the changes within the formation and effects on hydraulic fracturing performance. This study focuses on investigating flowback water/rock interactions during hydraulic fracturing in Marcellus Shale. Simple deionized water (DI)/rock interactions and complicated flowback water/rock interactions were studied under static and dynamic conditions. In static experiments, crushed reservoir rock samples were exposed to water for 3 weeks at room condition. In the dynamic experiment, continuous water flow interacted with rock samples through the coreflooding experimental system for 3 hours at reservoir condition. Before and after experiments, rock samples were characterized to determine the change on the rock surfaces. Water samples were analyzed to estimate the particle precipitation tendency and potential to modify flow pathway. Surface elemental concentrations, mineralogy, and scanning electron microscope (SEM) images of rock samples were characterized. Ion contents, particle size, total dissolved solids (TDS), and zeta-potential in the water samples were analyzed. After flowback water/rock interaction, the surface of the rock sample shows changes in the compositions and more particle attachment. In produced water, Na, Sr, and Cl concentrations are extremely high because of flowback water contamination. Water parameters show that produced water has the highest precipitation tendency relative to all water samples. Therefore, if flowback water without any treatment is reused in hydraulic fracturing, formation damage is more likely to occur from blockage of pores. Flowback water management is becoming very important due to volumes produced in every hydraulic fracturing operation. Deep well injection is no longer a favorable option because it results in disposal of high volumes of water that cannot be used for other purposes. A second option is the reuse of waste water for fracturing purposes, which reduces freshwater use significantly. However, the impurities present in flowback water may deteriorate the fracturing job and reduce or block the hydraulic fracturing apertures. This study shows that a simple filtration process applied to the flowback water allows for reinjection of the flowback water without further complication to the water/rock interaction, and does not cause significant formation damage in the fractures.