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Results
- Well Completion > Hydraulic Fracturing (0.40)
- Health, Safety, Environment & Sustainability > Environment > Water use, produced water discharge and disposal (0.40)
It is common knowledge that hydraulic fracturing operations require a lot of water, and as they have become a more vital element of the oil and gas industry, sourcing this water has proven to be a challenge for companies operating in tough terrain. Drought plagues much of the United States, a country with significant hydraulic fracturing activity, and operators have to take hydrology concerns into consideration when constructing facilities in these environments. In most cases, the solution means recycling produced and flowback water and diminishing, or eliminating altogether, the need for fresh water. Depending on the region and its specific challenges, operators are finding unique ways to address the water issue. In the past couple of years, new facilities have been built or repurposed with new technologies that may affect how companies work in water-stressed shale plays in the future. Where are these new facilities with these new technologies, and how will they help operators solve the problem of finding water to use in an expanding sector of the industry?
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Health, Safety, Environment & Sustainability > Environment > Water use, produced water discharge and disposal (1.00)
- Management > Energy Economics > Unconventional resource economics (0.86)
Recently, exploration and development of shale plays in Argentina, such as the Vaca Muerta, have begun. To achieve commercial production, this type of reservoir must be stimulated by hydraulic fracturing using large volumes of water. This paper discusses aspects of water logistics necessary during the well-completion phase, fracture-treatment designs applied in Vaca Muerta, and laboratory studies performed on flowback and produced water to help evaluate the potential for water reuse. Well stimulation using hydraulic fracturing has been used widely for producing oil and gas reservoirs in Argentina since the 1960s. This stimulation technique has been applied in the five hydrocarbon-producing basins shown in Figure 1 (above), as well as in a variety of formations and types of reservoirs, such as conventional, tight, and, more recently, shale.
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Vaca Muerta Shale Formation (0.99)
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Vaca Muerta Field > Vaca Muerta Shale Formation (0.98)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Colorado Field (0.93)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Production and Well Operations (1.00)
- (2 more...)
The recycling of produced water and fracture flowback water for reuse in hydraulic fracturing is on the rise in the development of unconventional resource plays. The factors driving the conservation of water are the limitations in sources of fresh water in areas with a high rate of development, the attractive economics of recycling compared with tanker truck transportation costs, minimization of road traffic to reduce environmental impacts, and water disposal costs. Fracture fluid, which ranges from water to slickwater and gels, requires fresh water as a makeup fluid to achieve consistency in the composition of the fracturing fluid and optimal fracture results. Traditional sources of fresh water for hydraulic fracturing include glacial and bedrock aquifer systems, surface waters, and municipal supplies. In its April 2010 report, "Bakken Water Opportunities Assessment--Phase 1," the University of North Dakota's Energy and Environmental Research Center (EERC) cited current water-handling costs in the Bakken (Table 1) as reported by several producers in the state.
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Pennsylvania > Appalachian Basin > Marcellus Shale Formation (0.99)
- (6 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Management > Energy Economics > Unconventional resource economics (1.00)
- Health, Safety, Environment & Sustainability > Environment > Water use, produced water discharge and disposal (1.00)
The recycling of produced water and fracture flowback water for reuse in hydraulic fracturing is on the rise in the development of unconventional resource plays. The factors driving the conservation of water are the limitations in sources of fresh water in areas with a high rate of development, the attractive economics of recycling compared with tanker truck transportation costs, minimization of road traffic to reduce environmental impacts, and water disposal costs. Fracture fluid, which ranges from water to slickwater and gels, requires fresh water as a makeup fluid to achieve consistency in the composition of the fracturing fluid and optimal fracture results. Traditional sources of fresh water for hydraulic fracturing include glacial and bedrock aquifer systems, surface waters, and municipal supplies. In its April 2010 report, "Bakken Water Opportunities Assessment--Phase 1," the University of North Dakota's Energy and Environmental Research Center (EERC) cited current water-handling costs in the Bakken (Table 1) as reported by several producers in the state.
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Pennsylvania > Appalachian Basin > Marcellus Shale Formation (0.99)
- (6 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Management > Energy Economics > Unconventional resource economics (1.00)
- Health, Safety, Environment & Sustainability > Environment > Water use, produced water discharge and disposal (1.00)
Effect of Pyrite Oxidation on Flowback Water Properties During Hydraulic Fracturing in Calcite-Rich Shales
Zeng, Lingping (Curtin University) | Iqbal, Muhammad Atif (Curtin University) | Reid, Nathan (CSIRO) | Lagat, Christopher (Curtin University) | Hossain, Md Mofazzal (Curtin University) | Saeedi, Ali (Curtin University) | Xie, Quan (Curtin University)
Abstract Megalitres of water with associated dissolved oxygen are injected into shale reservoirs during the hydraulic fracturing process. Pyrite oxidation, if it occurs in-situ, can generate extra H, thereby dissolving calcite and increasing the salinity of flowback water. The process of calcite dissolution may soften the hydraulic fracture surfaces, resulting in proppants embedment and thus decreasing fracture conductivity for calcite-rich shales. Therefore, it is of vital importance to understand the impact of in-situ pyrite oxidation on fluid-shale interactions, particularly calcite dissolution, to help industry screen and design hydraulic fracturing fluids in shales. Spontaneous imbibition experiments were performed using Marcellus shale samples under three conditions: i) ambient conditions, where the fluid was in equilibrium with atmospheric air throughout the tests, ii) limited O2 condition, where the fluid was free equilibrated with air in a sealed cylinder and iii) vacuum condition, where the fluid in a sealed cylinder was degassed. The pH and ion concentrations were measured upon completion of the experiments. To further explore how pyrite oxidation affects fluid-rock interactions, we performed geochemical simulations with considerations of mineral dissolution (calcite, albite, quartz, chalcopyrite, pyrite and dolomite), surface complexation and the dissolved O2 on fluid salinity. The spontaneous imbibition tests show that the salinity of fluids in ambient conditions is higher than the limited or vacuumed saturation fluids, confirming that pyrite oxidation generates H which would dissolve minerals such as calcite and dolomite. This result is also supported by the observed pH and the concentration of dissolved Ca. The fluid fully saturated with O2 has the lowest pH and highest Ca compared to limited O2 saturation condition and degassed condition. Scanning electron microscopy analyses show that brine saturation barely affects the morphology and elemental distribution of pyrite at ambient conditions, suggesting that pyrite oxidation plays a minor role in fluid salinity. Geochemical modelling also indicates that although pyrite oxidation can slightly increase fluid salinity, the salinity increment is less than 5% of reported flowback water salinity, confirming that the dissolved O2 in hydraulic fracturing fluids has a minor effect on fluid-rock interaction thus the salinity increment. This work demonstrates that pyrite dissolution at lab-scale would overestimate the impact of fluid-shale interactions and calcite dissolution in reservoir conditions. We prove that pyrite dissolution in in-situ conditions results in minor implications for fluid-shale interactions and calcite dissolution. Consequently, we limit intrinsic uncertainty of hydraulic fluid design associated with pyrite oxidization especially for calcite-rich shales.
- North America > United States > West Virginia (0.89)
- North America > United States > Pennsylvania (0.89)
- North America > United States > Virginia (0.67)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Mineral > Sulfide > Iron Sulfide > Pyrite (1.00)
- Geology > Mineral > Carbonate Mineral > Calcite (1.00)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Health, Safety, Environment & Sustainability > Environment > Water use, produced water discharge and disposal (1.00)
Future of Hydraulic Fracturing Application in Terms of Water Management and Environmental Issues: A Critical Review
Ellafi, Abdulaziz (University of North Dakota) | Jabbari, Hadi (University of North Dakota) | Tomomewo, Olusegun S. (Institute for Energy Studies,University of North Dakota) | Mann, Michael D. (Institute for Energy Studies,University of North Dakota) | Geri, Mohammed Ba (Missouri University of Science and Technology) | Tang, Clement (University of North Dakota)
Abstract Hydraulic fracturing technology requires securing sufficient water resources to access and unlock the pores of unconventional formations. Therefore, successful treatment depends on the fracture fluids, which mainly consist of water-based fluids with a low percentage (around 1%) of chemical additives. However, the oil and gas industry is among the largest freshwater consumers: three to six million gallons of water per well based on the number of fracturing stages. As a result, traditional water resources from subsurface and surface supplies are getting depleted, and freshwater is becoming more difficult to access with higher costs associated with continued demand. For example, operator companies in West Texas face many challenges, including a recent increase from USD 2 to 8 per barrel of freshwater. Also, the transportation of raw water to fracture sites, such as the Bakken shale play, has an environmental impact, with costs of up to USD 5 per barrel, while costs of water disposal range from USD 9 per barrel. This paper aims to investigate produced water as an alternative water-based fluid to several fracture fluids, such as crosslinked, linear gel, and high viscosity friction reducers (HVFRs) to reduce environmental footprints and economic costs. The workflow of this research started with a comprehensive review of extant publications, reports, and case studies to summarize the application of produced water with fracturing fluids in unconventional shale plays, such as the Bakken (North Dakota), Barnett (Texas), Eagle Ford (Texas), Wolfcamp (Texas), Marcellus (Pennsylvania), and Periman Bain (Texas). The critical review begins with explaining the features of produced water, its challenges, and water management options. Furthermore, the different fracturing fluids in a high TDS environment are described using recent lab fluid characterizations of produced water as 10% to 50% of produced water usage at a temperature range between 70 to 210 deg F. Moreover, 2D and 3D pseudo frac simulations are utilized using real field data from the Middle Bakken Formation to construct reliable models to evaluate the feasibility of reused water in shale plays development. The outcomes show that recycling water with high TDS in a high-temperature environment can create a fracture network and proppant transport when high viscosity friction reducers with surfactant (HVFR-PRS) was used. In addition, the result of this critical review is a powerful tool for predicting the future of hydraulic fracturing technology, which might help operator companies reduce costs and develop unconventional wells successfully for a return on their investment. The opportunities and challenges conclusions of water management are provided a survey of future hydraulic fracturing applications in North American shale plays by offering recommendations of environmental and economic impacts. The general guidelines obtained can promote the sustainability of using hydraulic fracturing treatment to produce more oil and gas from unconventional resources without compromising on environmental issues.
- North America > United States > Texas (1.00)
- North America > United States > North Dakota (1.00)
- Research Report > New Finding (0.93)
- Overview (0.68)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Treatment (0.94)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.66)
- North America > United States > South Dakota > Williston Basin > Bakken Shale Formation (0.99)
- North America > United States > North Dakota > Williston Basin > Bakken Shale Formation > Middle Bakken Shale Formation (0.99)
- North America > United States > Montana > Williston Basin > Bakken Shale Formation (0.99)
- (42 more...)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- (3 more...)
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.
- North America > United States > West Virginia (1.00)
- North America > United States > Virginia (1.00)
- North America > United States > Pennsylvania (1.00)
- (3 more...)
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.87)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play > Shale Gas Play (0.85)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics (1.00)
- Health, Safety, Environment & Sustainability > Environment > Water use, produced water discharge and disposal (1.00)
The geochemical fingerprinting of produced water has been identified as a practical tool for operational applications in the petroleum industry. Provenance studies of produced water are essential to trace flow dynamics and reservoir compartmentalization in petroleum systems and to quantify fluid recovery rates from unconventional fracturing. Due to the fact that recovered oilfield water samples are frequently contaminated by operational fluids (i.e., oil-based mud, water-based mud, completion brines or stimulation fluids), representative samples for reservoir fluids have to be filtered from the geochemical data set of produced water. Besides the routine analysis of major elements (Na, Ca, Mg, K, Cl, SO4, HCO3), an enhanced geochemical monitoring program with selected minor and trace elements (i.e., B, Ba, Li, Sr), environmental isotopes (i.e., deltaH, deltaO, Sr/Sr) and radiogenic isotopes (i.e., H, C) can provide in-depth information on the provenance of recovered oilfield water. Provenance studies of flowback water from hydraulic fracturing assets represent an enhanced method to assess the efficiency of the fracturing process by quantifying the recovered volume of originally injected fracturing fluid during the post-fracturing phase. The combination of gas recovery rates with geochemical flowback efficiency resulted in a practical tool to characterize the type and complexity of natural and induced fractures. Two cases studies showed that the combination of high gas recovery rates with low backflow efficiencies imply the presence of a complex system of natural and induced fractures. As a practical outcome, geochemical fingerprinting of recovered fluids can improve operational strategies for performed fracturing assets by avoiding water-pay zones, minimizing the amount of required fracturing fluids for injection purposes, and economizing the recycling process for recoverable flowback fluids. For the drilling of exploration or production wells, the presence of overpressured formations with a sudden water cut can frequently cause a technical challenge during well cementation. The design of a filtered geochemical database with regional fingerprints of formation water and groundwater zones is essential to identify the specific interval of water breakthrough for well plugging solutions. The routine geochemical analysis of reference water types, such as supply water and mud filtrate from the drilling process, is mandatory to quantify the potential flowback of applied drilling fluids.
- North America > United States > Pennsylvania (0.70)
- Asia > Middle East > Saudi Arabia (0.48)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.34)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Geochemical characterization (1.00)
- Health, Safety, Environment & Sustainability > Environment > Water use, produced water discharge and disposal (1.00)
Mitigation of Calcium Sulfate Scale Deposition during Fracturing Treatment of Unconventional Gas Wells
Sadykov, Almaz (Saudi Aramco) | Al-Dahlan, Mohammed (Saudi Aramco) | Mechkak, Karim (Saudi Aramco) | Al-Khaldi, Mohammed (Saudi Aramco) | Al-Otaibi, Fares (Saudi Aramco) | Al-Sayed, Mohammed (Saudi Aramco) | Al-Mulhim, Nayef I (Saudi Aramco)
ABSTRACT The objective of this paper is to study and mitigate the calcium sulfate (CaSO4) precipitation in proppant fracturing of unconventional gas wells in a carbonate formation. With sulfate content in the source water ranging from 500 to 2,000 ppm, and with up to 200,000 ppm total dissolved solids in the flowback water, calcium sulfate scale precipitation hindered fracture productivity and was considered an extreme challenge. Flowback water analysis revealed an abundance of calcium ions, mainly because of rock dissolution while having insignificant formation water presence in the source rock. Based on scaling tendency simulation results, an experimental study was conducted at the reservoir downhole temperature of 280 °F, to evaluate the flowback water compatibility with the source water used for fracturing fluids, simulating the contact of frac water with the formation. The sulfate content varied up to 2,000 ppm in the fracturing fluids. This paper addresses: 1) the scale tendency of sulfate-containing fracturing water with flowback (formation) water interaction; 2) examples of different scale inhibitors’ efficiency at different concentrations; 3) the fracturing fluids stability with scale inhibitors; 4) field trial performance for the selected scale inhibitor in an unconventional gas well; and 5) extensive flowback analysis and monitoring program during well clean out. Based on the static scaling tendency analysis in the laboratory, several findings were concluded. Acids and spacer stages must be prepared using fresh water; all high pH gelled fluids should be prepared using relatively low (≤ 500 ppm) sulfate (SO4)-containing water. An optimized multistage propped fracturing stimulation was conducted, and led to improved well performance with significant production increase compared to offset wells. Implementation of the recommended measures, including usage of low sulfate-containing water wells, addition of approved scale inhibitors, monitoring of water quality, etc., have showed no scales formation during well intervention and production operations, which was also confirmed by the flowback water analysis. A journey of learned lessons within a laboratory study-field test-laboratory study loop, serves as a solid guideline for all future propped fracturing jobs which involve a challenging water source and high TDS formation water composition. The present work exhibited an effective methodology to prevent potential formation damage induced by fracturing treatments.
- Asia > Middle East > Saudi Arabia (0.28)
- South America > Brazil > Rio de Janeiro (0.28)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (0.98)
- South America > Brazil > Campos Basin (0.99)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Campos Basin > Garoupa Cluster > Namorado Field (0.98)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)