Flowback Water Research Articles

Analysis of Chemical and Toxicological Properties of Fluids for Shale Hydraulic Fracturing and Flowback Water

Analysis of Chemical and Toxicological Properties of Fluids for Shale Hydraulic Fracturing and Flowback Water

To What Extent Could Shale Gas “Fracking” Contaminate Ground Water

The possibility to economically produce gas from unconventional natural resources (shale gas) reservoirs has been made possible recently through horizontal well and hydraulic fracturing application. Hydraulic fracture or ‘fracking ‘is a technique that use in combination with horizontal drilling to stimulate or improve extracting natural gas from shale formation. However, this operation requires large volume of fluid to be pumped into the well at high pressure and flow rate in order to split the rock. This fluid is mainly water and mixed with sand and some chemical materials such as proppant. (Serve to prop open the fracture). Injection large volume of fluid into subsurface is not without risk. The recent report have highlighted the following issues: (earthquake induced by slip on nearby fault, emission of CO2 into atmosphere) However, this project focus on the effect of fracking operation on ground water and aquifer due to chemical additives and methane which is the main composition of shale gas. According to this report the gases and chemical additives may escape and flow into overlying ground water ‘aquifer’ in three possible pathways. Loss of wellbore integrity disposal of flow back water natural fracture network. This paper also looks at two case studies, North-East Pennsylvania, New York and Wyoming in the USA, which have the same geological shale formation. The study focuses on finding the potential impact of fracking technique that is used to extract natural shale gas on ground drinking water systems.

The Role of High Density Polyethylene (HDPE) Lined Ponds in Treating Water for the Oil and Gas Industry

Introduction The problem to be solved is the disposal of millions of liters (gallons) of production water and flow-back water generated annually from the Rocky Mountain Region oil and gas industry ...

Water-Management Approach for Shale Operations in North America

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 167057, ’Water-Management Approach for Shale Operations in North America,’ by C. Kuijvenhoven, V. Fedotov, D. Gallo, and P. Hagemeijer, Shell, prepared for the 2013 SPE Unconventional Resources Conference and Exhibition - Asia Pacific, Brisbane, Australia, 11-13 November. The paper has not been peer reviewed. Produced-water (PW) and flowbackwater (FW) quality in shale projects is influenced not only by the formation, but also by the fracturing fluid introduced to the formation during hydraulic stimulation. The water produced by shale wells can contain suspended solids, dissolved solids, organics that include hydrocarbons and residual-fracturing-fluid chemicals, and bacteria. This paper describes functional water-treatment steps that target the most common removal of suspended solids and oil or condensate from PW and FW for recycling or disposal operations. Introduction Rapid industry expansion into shale-gas and -oil development requires a reconsideration of how water management and technology are applied. What may be acceptable and fit for purpose at a smaller scale may become unsatisfactory when the business grows significantly. Water footprint and the food/stress nexus are critical concerns requiring the industry to improve continuously upon the approach followed in the past. Selection of external water sources, securing access rights, and establishing water-offtake limits are the focus areas of water management. In some areas, freshwater resources may be scarce and the water for fracturing may need to be transported over long distances, adding to operational intensity and transportation-safety risks. Multiple steps are required to move the water for multiple consumers and to multiple locations. Storage facilities are required to create buffer capacity between water supply and water demand (Fig. 1). Recycling of PW and FW for fracturing will reduce the consumption of new water from external sources and reduce the volume of wastewater disposal. While disposal of PW into subsurface formations can be relatively inexpensive, requirements to obtain permits for this injection are becoming more stringent. On the other hand, if suitable injection zones are not available near the producing shale development, surface discharge needs to be considered. If surface discharge is the only option, then evaporative or zero-liquid-discharge (ZLD) technologies could be required, but this could be cost-prohibitive. Technical Challenges Water Characterization. For the purposes of this paper, the two water categories can be distinguished as follows: PW is managed by the production team controlling the wells for the remainder of well lifetimes. FW is produced when the completions team controls the well. This period is typically days or, at maximum, a few weeks after fracture stimulation.

Will water scarcity in semiarid regions limit hydraulic fracturing of shale plays?

There is increasing concern about water constraints limiting oil and gas production using hydraulic fracturing (HF) in shale plays, particularly in semiarid regions and during droughts. Here we evaluate HF vulnerability by comparing HF water demand with supply in the semiarid Texas Eagle Ford play, the largest shale oil producer globally. Current HF water demand (18 billion gallons, bgal; 68 billion liters, bL in 2013) equates to ∼16% of total water consumption in the play area. Projected HF water demand of ∼330 bgal with ∼62 000 additional wells over the next 20 years equates to ∼10% of historic groundwater depletion from regional irrigation. Estimated potential freshwater supplies include ∼1000 bgal over 20 yr from recharge and ∼10 000 bgal from aquifer storage, with land-owner lease agreements often stipulating purchase of freshwater. However, pumpage has resulted in excessive drawdown locally with estimated declines of ∼100–200 ft in ∼6% of the western play area since HF began in 2009–2013. Non-freshwater sources include initial flowback water, which is ≤5% of HF water demand, limiting reuse/recycling. Operators report shifting to brackish groundwater with estimated groundwater storage of 80 000 bgal. Comparison with other semiarid plays indicates increasing brackish groundwater and produced water use in the Permian Basin and large surface water inputs from the Missouri River in the Bakken play. The variety of water sources in semiarid regions, with projected HF water demand representing ∼3% of fresh and ∼1% of brackish water storage in the Eagle Ford footprint indicates that, with appropriate management, water availability should not physically limit future shale energy production.

Advanced Technologies for Produced-Water Treatment and Reuse

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 17394, ’Advanced Technologies for Produced-Water Treatment and Reuse,’ by A. Hussain, J. Minier-Matar, A. Janson, S. Gharfeh, and S. Adham, ConocoPhillips, prepared for the 2014 International Petroleum Technology Conference, Doha, Qatar, 20-22 January. The paper has not been peer reviewed. Historically, the treatment of produced water (PW) has been limited to free-oil and suspended-solids removal, using physical separation technologies and injection in disposal wells. However, because of new regulations, combined with geological restrictions and local water scarcity, the drive to have a greater fraction of the PW treated more extensively and ultimately to be reused is increasing. This paper presents the results of a laboratory investigation in which treatment processes were evaluated as treatment methods for PW from different oil and gas fields. Introduction A combination of factors is putting great pressure on operators to find new ways of treating and managing PW that promote water conservation and sustainability. However, treating PW to produce a good-quality effluent is a challenging task. PW characteristics can vary considerably. In order to treat PW to a water-quality standard that enables it to be reused, advanced water-treatment technologies (AWTTs) have to be applied, alone or in combination. To investigate the suitability of several AWTTs to treat and reuse PW from Qatari gas fields, the authors, in conjunction with an operator’s research center, carried out a laboratory investigation in which various treatment processes were evaluated. Four treatment methods were selected to target main contaminants identified in PW from a Qatari gas field: Membrane processes were used to target field chemicals, membrane-distillation (MD) methods were used to target salinity, membrane-bioreactors (MBRs) were used to target organics, and ozonation was used to target field chemicals. Overview of AWTTs Membrane Processes. The potential for membrane processes to treat PW has been demonstrated successfully in various field studies; moreover, a number of upstream petroleum full-scale facilities have already installed membrane processes to treat and reuse PW. The treatment trains either are a combination of different membrane processes or involve other conventional water-treatment technologies such as media filtration or clarification. For two case studies involving the use of membrane processes, please see the complete paper. Thermal Evaporators. These entered the PW-treatment market by finding niche opportunities. Moreover, because almost all waste streams are recycled back to the evaporator, the volumes of fresh water required for makeup are dramatically reduced. With the proliferation of shale-gas wells in the past decade in the US, the demand for treating flowback water with total-dissolved-solids (TDS) concentrations greater than 100 000 mg/L has expanded the opportunities for thermal systems. Another niche market in which the application of evaporators has been very successful is the steam-assisted- gravity-drainage enhanced-recovery process. MBRs. MBRs are now considered by the downstream petroleum industry as an excellent solution to treat various wastewater streams. Although MBRs have not yet been applied to treat PW at upstream oil and gas facilities, a number of bench-scale and pilot studies report that PW is biodegradable, achieving chemical-oxygen-demand (COD) and oil-and-grease (O&G) removals greater than 95%. Moreover, full-scale MBRs are also operating successfully in other industries, treating highly contaminated organic streams (COD greater than 15 000 mg/L) and achieving COD removals greater than 95%.

Iodine as a sensitive tracer for detecting influence of organic-rich shale in shallow groundwater

Public and regulatory agencies are concerned over the potential for drinking water contamination related to high-volume hydraulic fracturing (hydrofracking) of the Marcellus shale in Pennsylvania and in New York State (NYS), where exploitation of Marcellus gas has not yet begun. Unique natural tracers are helpful for distinguishing the influence of formation water and/or flow-back water. Here we use halogen concentrations, particularly bromine and iodine, to characterize natural variability of baseline water chemistry in the southern tier of NYS. Majority of streams and drinking water wells have Br and I concentrations below 1 and 0.1μM, respectively, a range typical for relatively pristine surface water and shallow groundwater. Wells that have higher Br and I concentrations are likely affected by formation waters. Br/I ratios indicate two different sources of formation waters in these wells, possibly controlled by geologic settings. Our results suggest that iodine, combined with other halogens, may be a novel and sensitive tool for fingerprinting trace levels of formation water signal in drinking water sources.

Microbial Dynamics and Control in Shale Gas Production

Microorganisms can cause detrimental effects in shale gas production, such as reservoir souring, plugging, equipment corrosion, and a decrease in hydrocarbon production volume and quality, thus representing a multi-billion-dollar problem. Prefracturing fluids, drilling mud, and impoundment water likely introduce deleterious microorganisms into shale gas reservoirs. Conditions within the reservoir generally select for halotolerant anaerobic microorganisms. Microbial abundance and diversity in flowback waters decrease shortly after hydraulic fracturing, with Clostridia, a class that includes spore-forming microorganisms, becoming dominant. The rapid microbial community successions observed suggest biocides are not fully effective, and more targeted treatment strategies are needed. At the impoundment level, microbial control strategies should consider biocide rotation, seasonal loading adjustments, and biocide pulse dosing. In shale plays where souring is common, stable 34S/32S isotope analysis to identify a...

As Scarcity Hits, Water Tech Flows In

Water Treatment Although the oil and gas boom in the United States owes much of its success to the abundance of cheap sources of fresh water, the status quo is beginning to change. Groundwater remains the main source of water for most onshore exploration and production companies; however, they are increasingly investing in produced and flowback water- treatment technologies. Many of the same companies are also turning to brackish water sources in places where freshwater aquifers are becoming depleted, such as the Permian Basin that spans west Texas and eastern New Mexico. Brackish water, sometimes called fossil water, has less salt content than seawater, making it cheaper to treat, and is typically found in the same areas where hydrocarbons are developed. The Fasken Oil and Ranch in Midland, Texas, relies on produced-water recycling and brackish water for nearly all of its oil and gas operations at its primary operating area. In August, a larger operator in the area called to buy produced water from Fasken, said Jimmy Davis, operations manager at the family-owned oil company. The friendly request exemplifies the increasingly desperate water situation that oil companies are facing in the Permian Basin, one of the most productive onshore areas in North America. “They are in a fix for water,” Davis said. “I am starting to hear that over and over. What we are doing out here as an industry is using water to frac, and we are in a drought-stricken area so you have to find other means than fresh water to meet those needs.” Based on the number of inquiries and activity that he is seeing from neighboring companies, Davis said he predicts that over the next few years, a majority of Permian Basin operators will turn to brackish and produced water as their primary sources. “If you are going to continue to frac like we are, that is what you are going to have to do to sustain it,” he said. According to a market analysis report by Houston-based PacWest Consulting, onshore oil and gas companies in the United States spent USD 20.1 billion last year on water-management services. While only 4% of the spending was for water treatment, if projections hold true, then this year will mark the turning point. The report said that water treatment represents the smallest yet fastest growing segment of the water-management market with a forecast of 23% growth each year to USD 1.3 billion by 2016. “Prevailing drought conditions and long-term sustainability of freshwater sources is expected to steadily increase demand for treatment services,” the report concluded.

E&P Notes (October 2014)

Heavy Oil Venture Testing New Way To Control Flames and Emissions byStephen Rassenfoss, JPT Emerging Technology Senior Editor A major heavy oil producer in California has agreed to test a device that is designed to reduce emissions of smog-producing gases and increase the efficiency of gas burners. Aera Energy, a joint venture of Shell and ExxonMobil, said it has agreed to retrofit a steam-generating unit used to heat heavy oil by using a new approach from ClearSign Combustion, a small publicly traded Seattle-based company whose mission is finding new ways to manage flames using a range of industrial processes. Its first offering will be tested in boilers used by Aera to create steam to reduce the viscosity of extremely thick crude so it can be pumped from the Belridge oil field in Kern County, California. The company said it wants to see if the technology, which is designed to achieve ultralow emissions (5 ppm) of nitrogen oxide, or NOX, can help it meet a mandate from the San Joaquin Valley Unified Air Pollution Control District to reduce NOX, a component in smog, to 9 ppm or less. The ClearSign technology is the size of the flame. Its Duplex tile technology is designed to replace methods that create flames stretching out more than 10 ft with thousands of smaller ones no more than 6 in. tall, according to videos on its website. The new approach performs differently because “we have mixed fuel and air prior to ignition. The oxygen will diffuse more rapidly for shorter flames,” said Rick Rutkowski, chief executive officer of ClearSign. The key component is the thick tile on top of a gas mixing chamber, which channels a natural gas/oxygen mix through thousands of small passageways. Pad Sites Offer Openings for New Measurement Tools byStephen Rassenfoss, JPT Emerging Technology Senior Editor At the recent Unconventional Resources Technical Conference in Denver, a direct measurement of what is downhole was a theme of new products offered to operators who see the need for more data on what is working, what is not working, and what could be made to work better. The offerings had to strike a balance between gathering better data downhole and doing so at a price in line with the cost limits of companies grinding out profits by drilling hundreds of wells. And both are arriving at a time when multiwell pad sites are increasingly the focus of development. These clusters of wells reduce the space, time, and cost associated with completing multiple wells. One wants to consolidate more formation testing on site, and the other wants to sell data revealing how tightly spaced wells interact. While rolling out a tool for collecting cores and preserving their fluids, Don Westacott, chief adviser of global unconventional reservoirs at Halliburton, said the company is working on a new well-side testing service to guide development on pad sites that it expects to roll out early next year. A new tool from Baker Hughes will provide pressure and temperature data which, among other things, will allow decision makers to see if fractures from nearby wells or stages connect, creating communication that may or may not be a positive development. The data gathered is not new, but this is designed to do so at a lower cost. “They wanted fracture and early production monitoring, but at a lower cost,” said Thomas Scott, production line manager of well monitoring systems at Baker Hughes. Reusable Filtration Technology Under Development byTrent Jacobs, JPT Technology Writer A new type of organically modified silica glass that can remove a wide variety of oils and contaminants from produced and flowback water is showing promising results as it undergoes field trials. The material, commercially referred to as Osorb media, is sold by process technology provider ProSep, the only company licensed to supply it to oil and gas companies. The developer said that the media is unique to the world of filtration technologies because it can absorb and adsorb up to four times its dry mass and then be regenerated for reuse once the material has reached its sorption limit. The company has delivered four rental units and is building a larger system that is capable of regenerating the media in place. The first systems require that the media be changed out once it has filled up with hydrocarbons. The primary application that ProSep is developing the technology for is final stage polishing for water discharge from offshore production platforms and enhanced oil recovery (EOR) reinjection. Production companies have also expressed interest in using the technology as a pretreatment system on the front-end of reverse osmosis membranes to protect them from fouling.

Estimation of Effective-Fracture Volume Using Water-Flowback and Production Data for Shale-Gas Wells

Summary Primarily, gas-production data are the main tool used to analyze shale-gas reservoirs. Water production is not usually included in the analysis. In this paper, post-fracturing water flowback and long-term water production are added to the analysis. The water data are usually available but are analyzed separately and not combined with long-term gas-production data. In this paper, procedures and examples are presented, including water-flowback and water-production data, in the analysis of shale-gas wells using rate transient analysis. A number of simulation cases were run. Various physical assumptions were used for the saturations and properties that exist in the fracture/matrix system after hydraulic fracturing. Water flowback and long-term production periods were then simulated. The results of these simulations were compared with data from actual wells by use of diagnostic and specialized plots. These comparisons led to certain conclusions which describe well/reservoir conditions after hydraulic fracturing and during production. This paper shows the benefits of a new method for combining water-flowback and long-term water-production data in shale-gas analysis. Water-production analysis can provide effective-fracture volume which was confirmed by the cumulative produced water. This can help when evaluating fracture-stimulation jobs. It also shows some pitfalls of ignoring flowback data. In some cases, the time shift on diagnostic plots changes the apparent flow-regime identification of the early gas-production data as well as water production data. This leads to different models of the fracture/ matrix system. The presented work shows the importance of including water-flowback data in the long-term production analysis.

Assessing worker exposure to inhaled volatile organic compounds from Marcellus Shale flowback pits

Natural gas drilling sites employing hydraulic fracturing present a potential source of inhalation exposure to volatile organic compounds (VOCs) via the use of flowback pits. These open-air pits are used as a means of storing flowback water, a waste product of hydraulic fracturing, and represent an understudied source of VOC exposure for workers. The objective of this study was to assess this worker exposure and the resulting health risks for 12 VOCs present in flowback water stored in such an open reservoir on a drilling site. Flowback pit VOC mean, 2.5 percentile, and 97.5 percentile concentrations were used to model aqueous phase concentrations, and two models of volatilization were applied to estimate flux to the gas phase. A mass-balance approach was used to estimate gas phase concentrations that were, in turn, used to estimate worker exposure. A literature review was performed to determine VOC health effects, exposure limits, and worker protection methods. Neither model demonstrated an increased risk of adverse effects due to subchronic exposure at the 2.5 percentile and mean concentration values for the 12 VOCs as indicated by hazard quotients, hazard indices, or excess lifetime cancer risks; however, 97.5 percentile hazard indices approached 1 in one model and did demonstrate unacceptable risks in the evaluation of limitations. Either model may apply to worker health assessment depending upon industry practice; however, differing weather conditions, industry practice, and the small number of VOCs evaluated necessitate further research regarding worker risks and health effects.

Characterization of Marcellus Shale Flowback Water

Abstract Flowback water is the solution that returns to the surface following completion of the hydraulic fracturing process during natural gas extraction. This study examines and analyzes the constituents that make up flowback waters collected from various drilling sites in Marcellus shale formation in the states of Pennsylvania, New York, and West Virginia. Flowback sampling data were collected from four different sources (the Environmental Protection Agency, Gas Technology Institute; Pennsylvania Department of Environmental Protection; Bureau of Oil and Gas Management; and the New York Department of Environmental Conservation) and compiled into one database with a total of 35,000 entries. Descriptive statistical analysis revealed high concentrations of chlorinated solvents, disinfectants, dissolved metals, organic compounds, radionuclides, and total dissolved solids. A one-way ANOVA test revealed that over 60% of the constituents tested displayed significant differences (significance level=0.05) in mea...

Organic compounds in produced waters from shale gas wells.

A detailed analysis is reported of the organic composition of produced water samples from typical shale gas wells in the Marcellus (PA), Eagle Ford (TX), and Barnett (NM) formations. The quality of shale gas produced (and frac flowback) waters is a current environmental concern and disposal problem for producers. Re-use of produced water for hydraulic fracturing is being encouraged; however, knowledge of the organic impurities is important in determining the method of treatment. The metal content was determined by inductively coupled plasma optical emission spectrometry (ICP-OES). Mineral elements are expected depending on the reservoir geology and salts used in hydraulic fracturing; however, significant levels of other transition metals and heavier main group elements are observed. The presence of scaling elements (Ca and Ba) is related to the pH of the water rather than total dissolved solids (TDS). Using gas chromatography mass spectrometry (GC/MS) analysis of the chloroform extracts of the produced water samples, a plethora of organic compounds were identified. In each water sample, the majority of organics are saturated (aliphatic), and only a small fraction comes under aromatic, resin, and asphaltene categories. Unlike coalbed methane produced water it appears that shale oil/gas produced water does not contain significant quantities of polyaromatic hydrocarbons reducing the potential health hazard. Marcellus and Barnett produced waters contain predominantly C6-C16 hydrocarbons, while the Eagle Ford produced water shows the highest concentration in the C17-C30 range. The structures of the saturated hydrocarbons identified generally follows the trend of linear > branched > cyclic. Heterocyclic compounds are identified with the largest fraction being fatty alcohols, esters, and ethers. However, the presence of various fatty acid phthalate esters in the Barnett and Marcellus produced waters can be related to their use in drilling fluids and breaker additives rather than their presence in connate fluids. Halogen containing compounds are found in each of the water samples, and although the fluorocarbon compounds identified are used as tracers, the presence of chlorocarbons and organobromides formed as a consequence of using chlorine containing oxidants (to remove bacteria from source water), suggests that industry should concentrate on non-chemical treatments of frac and produced waters.

Mechanical Vapor Recompression for the Treatment of Shale-Gas Flowback Water

Summary Used extensively by the food, chemical, and pharmaceutical industries, the mechanical-vapor-recompression (MVR) process is viewed as a reliable method for recovering demineralized water from concentrated brines. Devon Energy has supported the operation of an advanced MVR system at a north-central Texas (Barnett shale region) treatment facility. At this facility, pretreatment included caustic addition and clarification for total-suspended-solids and iron control. Pretreated shale-gas flowback water was then sent to three MVR units, each rated at 2,000–2500 B/D (318–398 m3/d). Data were collected during a 60-day period in the summer of 2010. Distilled-water recovery volume averaged 72.5% of the influent water to the MVR units. The influent total dissolved solids (TDS) fed to the MVR units averaged just under 50 000 mg/L. More than 99% of the TDS were captured in the concentrate stream. The fate of multivalent cations; total petroleum hydrocarbons (TPH); and benzene, toluene, ethylbenzene and xylenes (BTEX) throughout the treatment system was determined. Most of the iron and TPH removal (90 and 84%, respectively) occurred during pretreatment. The total removal of iron, magnesium, calcium, barium, and boron from the distillate exceeded 99%. BTEX removal from the distillate exceeded 95%. Electric power at the facility was provided by two natural-gas generators, and compressors associated with the MVR units were driven by natural-gas-fueled internal-combustion engines. Energy requirements at the entire treatment facility were tracked daily by total natural-gas use. Best-fit correlations between treated water and distillate production vs. total plant use of natural gas indicated that there was a base power load throughout the facility of approximately 120 to 140 Mscf/D (3400 to 3960 m3/d) of gas. Approximately 48 scf natural gas/bbl influent water treated (270 m3/m3 influent) or 60.5 scf/bbl distillate produced (340 m3/m3 distillate) was required; this represents an energy cost of less than USD 0.25/bbl treated (USD 0.04/m3 treated) and approximately USD 0.30/bbl of distillate product generated (USD 0.048/m3 distillate), assuming a natural-gas cost of USD 5/million Btu (USD 4.72/GJ). Performance in terms of water recovery and product-water quality was stable throughout the 60-day test.

How Thirsty is Shale Gas?

Beyond the Headlines Editor’s note: Professionals in the oil and gas industry often receive questions about how industry operations affect public health, the environment, and the communities in which they operate. Of particular concern today is the impact of hydraulic fracturing on the environment. In this new column, JPT is inviting energy experts to put those questions and concerns about industry operations into perspective. Additional information about the oil and gas industry, how it affects society, and how to explain industry operations and practices to the general public is available on SPE’s Energy4me website at www.energy4me. org. The New York Times reported on 15 May 2014 that Butte County in California banned hydraulic fracturing because of concerns regarding freshwater consumption in a drought year. Shale oil and gas opponents have seized this issue even in parts of the country not suffering any significant drought. The perception of being deprived of drinking water has strong imagery. The facts beyond the headlines are decidedly not so dire. A single shale oil or gas well will use between 3 and 5 million gal of water for drilling and completion operations. This sounds like a lot and, in some sense, it is a lot. But then you realize that the average golf course uses that much every 25 days, about the length of time it takes to drill a single well and start producing from it. It is also the amount of water that New York City uses every 4 minutes! Not a fair comparison, you say. Well, why don’t we compare it against other forms of energy? Such comparisons are best made on the basis of liters of water per megawatt hour of energy. Shale gas production uses about 38 liters. In comparison, corn ethanol on average uses 32,000 to 370,000 liters (the higher end of the range is for irrigated corn), and the real shocker is soybean diesel, which comes in at 180,000 to 960,000 liters. In other words, corn ethanol uses more than 1,000 times more water per unit of energy compared with shale gas. Other sources suggest an even greater disparity in water usage (Science 2009). Conventional fracturing fluid uses freshwater as the base fluid. Fresh is defined as 500 parts per million (ppm) or less of dissolved solids. The fluid returning to the surface after use, known as flowback water, is always saltier than what went in. Salinities of 200,000 ppm are not uncommon. As a frame of reference, seawater runs about 35,000 ppm. Recent advances in fracturing fluid chemistry allow for such flowback water to be reused without removing the salt down to fresh standards. Currently in the Marcellus shale play, some companies are reusing almost all of their flowback water with minimal treatment.

C&EN Webinars - New Techniques for Anion, Cation, and Radioisotope Analysis of Marcellus Shale Flowback Waters

C&EN Webinars - New Techniques for Anion, Cation, and Radioisotope Analysis of Marcellus Shale Flowback Waters

Hydraulic fracturing and the management, disposal, and reuse of frac flowback waters: Views from the public in the Marcellus Shale

Issues associated with the public's views on hydraulic fracturing and the management, disposal, and reuse of frac flowback wastewaters are empirically examined in this paper. The data used in the analyses were collected in a general population survey from a random sample drawn from 21 counties located in the geological Central Core and Tier 1 of the Marcellus Shale region in Pennsylvania. Differences in the information reported by survey respondents living in high well-density counties (20 or more wells per 100 square miles) and their counterparts living in low well-density counties (fewer than 20 wells per 100 square miles) were examined. Substantive findings from the overall sample, as well as statistically significant differences between the two groups of respondents, are reported. The results contained in this paper should prove beneficial to members of the general public, community leaders, oil and gas industry representatives, government and regulatory agency personnel, environmental and non-governmental organization representatives, and other interested stakeholders.

Microfiltration in recycling of Marcellus Shale flowback water: Solids removal and potential fouling of polymeric microfiltration membranes

Flowback water generated during unconventional gas extraction is of great concern due to its high total dissolved solids (TDS), radioactive elements and organic matter. Abandoned mine drainage (AMD) is a water source that is often located in the vicinity of gas wells and can be mixed with flowback water to reduce fresh water usage for hydraulic fracturing. The feasibility of microfiltration to separate solids created by mixing actual flowback water and AMD was evaluated using a bench-scale setup. Hydrophilic polyvinyldiene fluoride (PVDF) membrane with a pore size of 0.22μm was as a model polymeric microfiltration membrane.Severe membrane fouling occurred during the first 5min of filtration with one flowback/AMD mixture while no significant fouling was observed for a different mixture. It was found that the flowback water that caused membrane fouling contained stable iron-based colloids with an average particles size of 0.2μm, especially in the samples collected early in the flowback period. These colloids were not formed by mixing flowback water containing high barium concentration with AMD rich in sulfate but were originally present in the flowback water. Stability of these sub-micron colloidal particles at high ionic strength of the flowback water is attributed to organic coating on the particle surface.

Applications of Oilfield Produced Formation Water for Fracturing Fluid

Oilfield produced formation water containing complex mixture of Dissolved Solid Compounds (DSC), including sodium, boron, chloride, magnesium, potassium, calcium, barium, iron and other salts is used in this research with the objective to develop stable and degradable cross linked fracturing fluid useful in both oil and gas producing reservoirs. As a result of recent increasing interest in horizontal drilling and hydraulic fracturing operations, large volume of produced and/or flow back water containing complex mixture of organic and inorganic compounds is generated in the oilfield during the oil and gas recovery operations. Independently owned to larger oil and gas producing operators manage the generated oilfield produced water by one or more of the strategies, which include disposal, re-use and recycling of the produced water. However, large water consumption and strict environmental disposal issues associated with hydraulic fracturing treatment, combined with industry growth, are generating a crucial need for developing a good viscosity and reliably stable cross linked fracturing fluid systems, useful for transporting propping agents into the fracturing zones at moderate to high temperature range using the generated oilfield produced water. Presented in this study are the results of rheology and residue analysis of fracturing fluid systems prepared with oilfield produced formation water from a broad spectrum of geologic basins. The rheology studies were conducted to measure viscosity under a nitrogen pressure of >400 Psi and temperature window of 210-260°F. The guar residue analysis test was performed with series of gel breakers at 185°F. The fluid systems presented provide proof of concept of the ability to crosslink and degrade cross linked fluids to below 100 cP at shear rate of 100/sec under the considered treating down hole conditions. Data presented provide guidance for the potential use of generated oilfield produced water as source water and/or blend water for water-shortage oil and gas producing operators and reducing the negative environmental impact.