|Exam Name||:||Symantec System Recovery 2011 Technical(R) Assessment|
|Questions and Answers||:||111 Q & A|
|Updated On||:||March 25, 2019|
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ST0-136 exam Dumps Source : Symantec System Recovery 2011 Technical(R) Assessment
Test Code : ST0-136
Test Name : Symantec System Recovery 2011 Technical(R) Assessment
Vendor Name : Symantec
Q&A : 111 Real Questions
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MOUNTAIN VIEW, CA--(Marketwire - 04/04/eleven) - Symantec Corp. (NASDAQ:SYMC - information) nowadays announced its strategy to deliver groups of all sizes with a tailored strategy to solve their facts, device and software healing challenges to greater meet stringent healing time objectives and hold their company up and running. As a part of its broader downtime remediation approach, Symantec is also supplying new recuperation updates and platform support to Symantec device recuperation 2011, formerly Backup Exec system recovery, for each actual and virtual environments.Symantec's downtime remediation strategy includes an optimal mix of solutions to resolve clients' restoration challenges:
click on to Tweet: Symantec device healing supplies flexible recuperation of physical and digital methods: http://bit.ly/ftlofu"Symantec presents confirmed know-how to support our customers improve facts, systems and purposes to avoid disruption to their business," talked about Amit Walia, vp of product administration, Symantec. "Symantec device recovery shortens the recovery time window with new elements such because the means to seriously change a USB machine right into a restoration disk and further flexibility to the customizable restoration disk wizard."Symantec analysis shows that mess ups can have a significant impact on a enterprise and groups of all sizes are vulnerable to downtime. Symantec's 2011 SMB disaster Preparedness Survey found that almost all of small agencies surveyed are nevertheless unprepared to take care of a disaster and 54 p.c of SMB consumer respondents pronounced they have switched SMB vendors as a result of unreliable computing methods. in a similar way, Symantec's 2010 disaster recovery Survey, which surveyed enterprise agencies, found that the time required to get well from an outage is twice so long as respondents understand it to be.obtainable now, Symantec system healing 2011 adds the following new facets:
connect with Symantec
About Storage from Symantec Symantec helps companies comfortable and manage their assistance-driven world with storage administration, e-mail archiving and backup & healing options.About Symantec Symantec is a worldwide leader in offering safety, storage and methods administration options to assist patrons and businesses comfy and manage their information-driven world. Our utility and services offer protection to against greater hazards at more features, extra absolutely and efficiently, enabling self assurance at any place assistance is used or stored. greater guidance is available at www.symantec.com.notice TO EDITORS: if you'd like additional information on Symantec organization and its products, please consult with the Symantec information Room at http://www.symantec.com/news. All fees referred to are in U.S. dollars and are valid best within the u.s..Symantec and the Symantec brand are emblems or registered logos of Symantec organization or its associates in the U.S. and different nations. other names can be emblems of their respective owners.Technorati Tags Symantec, Backup Exec, equipment healing, VMware, backup and restoration, small agencies
enterprise backup appliances help agencies modernize backup infrastructures, speed up virtualization initiatives.note: ESJ’s editors carefully opt for vendor-issued press releases about new or upgraded products and services. we have edited and/or condensed this unencumber to highlight key features but make no claims as to the accuracy of the supplier's statements.
Symantec Corp. has released Backup Exec 3600 and NetBackup 5220 business backup home equipment to help corporations modernize their backup infrastructures and accelerate new initiatives around virtualization with more desirable reliability. Symantec backup home equipment may also be deployed in as little as 30 minutes and help businesses offer protection to information absolutely, in physical or digital environments, and deduplicate facts all over the place to improve effectivity and reduce prices.
Backup Exec 3600: Visibility and content-mindful Deduplication throughout physical and virtual methods
geared up with Symantec V-Ray technology, Backup Exec 3600 appliance gives the same entertaining visibility into virtual environments as Backup Exec 2010 application to allow businesses to velocity healing times and reduce storage charges. Symantec Backup Exec 3600 is the first all-in-one backup equipment with integrated customer and goal facts deduplication for protecting virtual and physical machines for midsized companies with confined IT staff. Backup Exec 3600 will guide the upcoming free up of VMware vSphere 5 and is the most effective solution attainable with Backup Exec on optimized hardware and software.
Backup Exec 3600 is a simple and authentic backup appliance designed to in the reduction of IT complexity via providing:
NetBackup 5220: All-in-one Backup appliance Protects digital and actual techniques
Symantec NetBackup 5220 is a scalable backup appliance for commercial enterprise businesses with both client and target deduplication designed to accelerate backups for actual and virtual systems. based on NetBackup 7.1, the equipment comprises Symantec’s content material-mindful deduplication that can cut back backup extent and community utilization via as tons as ninety nine %, doing away with backup window complications and enabling budget friendly replication of statistics to different sites for enterprise continuity. NetBackup additionally has plans to help VMware vSphere 5 within the subsequent unencumber due out later this 12 months.
With the NetBackup 5220 appliance, agencies can:
Symantec NetBackup 5220 sequence and Backup Exec 3600 collection home equipment can be found now in North the united states. both home equipment will roll out in additional international locations in a phased method over the next yr. present NetBackup and Backup Exec clients can repurpose present licenses to install the NetBackup 5220 or Backup Exec 3600, respectively.
For additional info in regards to the Backup Exec 3600 equipment, discuss with http://www.symantec.com/enterprise/backup-exec-3600-appliance. For extra assistance about the NetBackup 5220 appliance is available right here.
Symantec Corp.'s OpenStorage technology (OST) API turned into in the beginning developed to deliver clients with a typical interface for third-birthday celebration disk backup targets. In Lauren Whitehouse's newest Storage magazine column, learn the way Symantec OpenStorage expertise influences information backup and healing nowadays, plus which vendors are aiding it.
EMC Corp. lately introduced its statistics domain world Deduplication Array (GDA) that optimizes statistics deduplication in tremendous-scale environments by using aggregating the records storage capacity of two of its deduplication appliances to enrich throughput performance and scale. when it comes to birth, one of the key enablers of GDA's means to distribute deduplicate processing is Symantec's OpenStorage know-how API.
Symantec OpenStorage expertise is an API for NetBackup (models 6.5 and better) and Backup Exec 2010. companions leverage the API to jot down a application plug-in module that's put in on the backup media server to talk with the storage equipment, developing tighter integration between the backup utility and goal storage. in short, it's an interface that speeds up backup for NetBackup purchasers. The best difficulty with OST is that it highlights the incontrovertible fact that different backup carriers don't offer an analogous skill.
Symantec OpenStorage API
at the start, the Symantec OpenStorage API was published to provide Symantec valued clientele with a typical interface to third-celebration disk objectives. It makes it possible for backup information to be saved on disk with anything protocol the target equipment uses, reminiscent of Fibre Channel (FC) or TCP/IP. Symantec backup utility sees OST-enabled appliances as disk and allows elements akin to intelligent capacity administration, media server load balancing, reporting and lifecycle policies.
It also gives you optimized facts duplication—network-effective replication and direct disk-to-tape (D2T) duplication it's monitored and cataloged through the backup application. with out Symantec OST, there are two scenarios: enable the storage equipment to switch information with out the backup catalog being privy to the copies, or transfer statistics from device to media server to gadget to maintain the backup catalog privy to the replica. in the first scenario, the backup catalog is ignored of the loop on the vicinity of backup copies. this can create complexity and bog down disaster healing methods. The latter state of affairs increases LAN, WAN and SAN network traffic, and gets rid of the benefits of deduplication in network switch. obviously, deduplication controlled with the aid of OST-enabled gadgets creates savings in each time and bandwidth requirements.
since the catalog is aware of all copies, recovery of records from an OST-optimized duplicate reproduction is an identical as recovery from a different replica. during the backup application, the OST-optimized duplicate reproduction may also be distinct as the basic replica, and then a full or granular recuperation can be initiated. The competencies time mark downs when in comparison to restoration from a non-OST-optimized reproduction can be significant.
seller OST adoption
Many backup target machine companies have subscribed to the Symantec OST API, which is rarely astonishing given its benefits and Symantec's market share. providers with aid for OST along side NetBackup and/or Backup Exec include EMC, ExaGrid, FalconStor application, GreenBytes, IBM, NEC, Quantum (the simplest vendor up to now to assist OST direct-to-tape aid with NetBackup) and Sepaton. it be also worthwhile to note that Symantec helps its own deduplication implementation in NetBackup and Backup Exec with OST.
one of the crucial through-items of the OST interface is a performance improvement in backup and restoration operations, with some providers claiming upwards of a one hundred% raise in efficiency. EMC's OST alternative for its records area home equipment changed into aptly renamed "boost," a testomony to its performance advantage. In creating its OST plug-in, EMC more desirable communications and optimized the packaging and transfer of information between backup media server and storage device, thereby improving efficiency.
EMC became extra ingenious with records domain GDA, taking expertise of the OST API to distribute a portion of the deduplication processing to the backup media server, which EMC claims lowers media server CPU utilization. and because deduplication happens past within the backup facts course, the implementation eliminates some redundant records on the media server, and reduces the community load between media server and storage.
In an analogous move, NEC leveraged the OST API to optimize load balancing. whereas one of the most inherent merits of OST is to enable disk pooling for more desirable overall backup gadget load balancing, NEC took issues a step further. Hydrastor, NEC's storage platform offering information deduplication, has a scale-out grid architecture using one or more logical storage units (records movers) and storage. through OST integration, the backup application can now instantly distribute jobs to the logical storage gadgets of the Hydrastor grid.
Disk and records deduplication well-known
Disk-primarily based backup is becoming more pervasive in facts protection thoughts; ESG analysis finds that the variety of companies the usage of handiest tape in backup operations dropped 27% between 2008 and 2010, with more groups favoring a disk-to-disk (56% increase) or disk-to-disk-to-tape (forty two% boost) strategy. statistics deduplication use grew more than 200% between 2008 and 2010.
When EMC launched records domain GDA, the business deliberate to circulation deduplication "upstream" by means of integration with EMC NetWorker. lamentably, the integration is probably going to be tough-coded into NetWorker due to the fact that NetWorker presently doesn't have an OST-equivalent API -- nor does every other backup dealer product.
or not it's also not likely that Symantec will make OST an open normal that different backup providers might use (corresponding to how NDMP is utilized through backup carriers to returned up filers). looking forward, it's greater doubtless we will see different backup carriers effort OST-like APIs.
Of direction, Symantec prices a fee to test and certify its OST partners' options. So it might get high priced for an organization like Quantum or records domain, as an instance, to certify its options with dissimilar backup items' APIs. In flip, end users are charged a premium fee for OST enablement—from each the backup supplier and the goal system seller. in addition, an conclusion consumer with multiple backup options (in this case Backup Exec and NetBackup) is likely to be required to pay license charges to Symantec for OST-enablement with every backup product.
About this writer: Lauren Whitehouse is an analyst specializing in backup and recovery utility, and replication options at business strategy community, Milford, Mass.
this article was up to now published in Storage magazine.
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By Daniel J. Weiss and Jackie Weidman
The United States was subjected to many severe climate-related extreme weather over the past two years. In 2011 there were 14 extreme weather events — floods, drought, storms, and wildfires — that each caused at least $1 billion in damage. There were another 11 such disasters in 2012. Most of these extreme weather events reflect part of the unpaid bill from climate change — a tab that will only grow over time.
CAP recently documented the human and economic toll from these devastating events in our November 2012 report “Heavy Weather: How Climate Destruction Harms Middle- and Lower- Income Americans.” Since the release of that report, the National Oceanic and Atmospheric Administration, or NOAA, has updated its list of “billion-dollar”-damage weather events for 2012, bringing the two-year total to 25 incidents.
From 2011 to 2012 these 25 “billion-dollar damage” weather events in the United States are estimated to have caused up to $188 billion in total damage.  The two costliest events were the September 2012 drought — the worst drought in half a century, which baked nearly two-thirds of the continental United States — and superstorm Sandy, which battered the northeast coast in late October 2012. The four recently added disastrous weather events were severe tornadoes and thunderstorms.
Here is an update of vital extreme weather event data after the addition of these four events:
Below are descriptions of each of the four weather events in 2012 that were not included in our previous report.
April 12: Tornadoes
Nearly 100 tornadoes touched down across Kansas and other midwest states over a two-day period in mid-April 2012, resulting in six deaths. Extensive damage to schools, hospitals, businesses, and homes was estimated to cost $1.8 billion. Many towns were without power for extended periods of time. Fourteen counties in Kansas were declared disaster areas because of the storms. Households in these disaster-declared counties earn, on average, an annual income of $47,027–9 percent below the U.S. median household income.
April 28: Severe Storms
Severe weather in Oklahoma and surrounding states caused at least $4 billion in damage and one confirmed fatality in late April 2012. Storm damage throughout the area was primarily caused by 38 confirmed tornadoes and severe hail. Oklahoma was most heavily impacted — six Oklahoma counties were declared disaster areas in the wake of the storm. Households in the counties that were disaster areas earn, on average, an annual income of $39,638 — a staggering 24 percent below the U.S. median household income.
May 25: Severe Storms
Twenty-seven confirmed tornadoes touched down over a broad swath of the United States, including from Oklahoma to New Hampshire. The tornadoes and outburst of severe hail, straight-line winds, and thunderstorms caused one fatality and approximately $2.5 billion in damage. Most of the damage occurred in Oklahoma and the entire state was declared a disaster area. New Hampshire and Vermont also had some disaster-declared counties. Households in these disaster-declared counties earn, on average, an annual income of $45,431–12 percent below the U.S. median household income.
June 29: Derecho
A derecho is a “widespread, long-lived wind storm that is associated with a band of rapidly moving showers or thunderstorms,” according to the National Oceanic and Atmospheric Administration. Such a storm ravaged eastern and northeastern states in June 2012. It caused 28 fatalities and ripped through a 700-sqaure-mile swath of the mid-Atlantic region, leaving 3.4 million homes there without power. The storm caused at least $3.8 billion in damage in 215 counties in Maryland, New Jersey, Ohio, West Virginia, Virginia, and Washington, D.C. All were declared disaster areas.
These events, along with the seven other “billion-dollar” weather events in 2012, made it the second-most-extreme weather year on record, according to the U.S. Climate Extremes Index.
NASA climatologist Gavin Schmidt says that when it comes to higher temperatures and extreme weather, “what matters is this decade is warmer than the last decade, and that decade was warmer than the decade before. The planet is warming. The reason is because we are pumping increasing amounts of carbon dioxide into the atmosphere.”
The U.S. National Climate Assessment draft released in January 2013 indicates that the effects of climate change will continue to threaten the health and vitality of our communities as extreme weather becomes more frequent and/or severe. One of the report’s key findings is that U.S. coastal communities are particularly vulnerable to sea-level rise, storms, floods, and subsequent erosion. And scientists predict that precipitation events across the United States are likely to be heavier. These risks pose serious threats to our electricity grid, infrastructure, clean water, and sewage treatment system in the most affected places.
The climate-related extreme weather events of the past several years have become the new normal. We must act now to reduce the industrial carbon pollution responsible for climate change and help communities become more resilient to the coming storms, floods, droughts, heat waves, and wildfires.
Disaster relief has suddenly become a partisan issue. This became overwhelmingly clear during recent debates in the Senate and the House of Representatives over the Disaster Relief Appropriations Act (H.R. 152), which provided $50.7 billion in emergency aid for superstorm Sandy victims.  The measure was passed by Congress and signed by President Barack Obama on January 29, 2013 — an unacceptable 91 days after the storm devastated the northeast corridor.
Despite passing with support from all but one voting Democrat in the House and Senate, the vast majority of Republicans in each chamber opposed essential aid to hurricane victims. These conservative lawmakers attempted to deny financial assistance to those in need, even after some of them previously requested disaster funding for their own states. All 36 Republican senators who voted against the Sandy aid bill are from states that experienced at least one “billion-dollar damage” extreme weather event in the past two years. In fact, 98 percent of lawmakers in either chamber who voted against the bill — 211 of the 216 Republicans — represent states that experienced at least one “billion-dollar damage” extreme weather event in the past two years.
The debate over congressional passage of disaster recovery assistance raises serious concerns about whether Congress can both aid disaster victims in a timely fashion and work to help communities minimize damages from future storms and other extreme weather. In order to help these communities reduce their vulnerability to extreme weather, Rep. Lois Capps (D-CA) and 37 of her colleagues urged President Obama to appoint a blue ribbon panel to develop a a “community resilience fund” dedicated solely to providing the financial and technical assistance to vulnerable communities hit by extreme weather events. Dedicated funding for predisaster mitigation will protect lives, shield middle- and lower-income households from the worst impacts of extreme weather, and save taxpayers money over time.
For more information on this proposal, please see CAP’s December 2012 column “An Ounce of Prevention: Increasing Resiliency to Climate-Related Extreme Weather.”Methodology
This Center for American Progress analysis compiled data from multiple sources. Extreme weather events data were from the National Oceanic and Atmospheric Administration’s National Climatic Data Center, or NCDC. Counties affected by each event were compiled from the Federal Emergency Management Agency’s Declared Disasters database.
In order to assess income levels for the most affected counties, we used median household income (2006–2010) data and number of households (2006–2010) data from the U.S. Census Bureau’s State and County QuickFacts. The 2006–2010 values are an average over the five-year period. We compared the percent difference between the average annual median household incomes for the affected counties in each weather event to the U.S. median — $51,914. We accounted for the population of each county when calculating these values. The cost per household was calculated by taking the cost of the event divided by the total number of households for each event.
 The National Oceanic and Atmospheric Administration will release final 2013 disaster cost estimates in mid-2013.
 U.S. median income figures are based on the 2005–2010 Census Bureau average.
 This was the second installment of Sandy aid. The first installment of $9.7 billion was passed on January 1, 2013.
Daniel J. Weiss is a Senior Fellow and Director of Climate Strategy at the Center for American Progress. Jackie Weidman is a Special Assistant at the Center.
Natural gas has recently emerged as a relatively clean energy source that offers the opportunity for a number of regions around the world to reduce their reliance on energy imports. It can also serve as a transition fuel that will allow for the shift from coal to renewable energy resources while helping to reduce the emissions of CO2, criteria pollutants, and mercury by the power sector. Horizontal drilling and hydraulic fracturing make the extraction of tightly bound natural gas from shale formations economically feasible. These technologies are not free from environmental risks, however, especially those related to regional water quality, such as gas migration, contaminant transport through induced and natural fractures, wastewater discharge, and accidental spills. The focus of this Review is on the current understanding of these environmental issues.
The most common problem with well construction is a faulty seal that is emplaced to prevent gas migration into shallow groundwater. The incidence rate of seal problems in unconventional gas wells is relatively low (1 to 3%), but there is a substantial controversy whether the methane detected in private groundwater wells in the area where drilling for unconventional gas is ongoing was caused by well drilling or natural processes. It is difficult to resolve this issue because many areas have long had sources of methane unrelated to hydraulic fracturing, and pre-drilling baseline data are often unavailable.
Water management for unconventional shale gas extraction is one of the key issues that will dominate environmental debate surrounding the gas industry. Reuse of produced water for hydraulic fracturing is currently addressing the concerns regarding the vast quantities of contaminants that are brought to the surface. As these well fields mature and the opportunities for wastewater reuse diminish, the need to find alternative management strategies for this wastewater will likely intensify.Outlook
Improved understanding of the fate and transport of contaminants of concern and increased long-term monitoring and data dissemination will help effectively manage water-quality risks associated with unconventional gas industry today and in the future. Confidentiality requirements dictated by legal investigations combined with the expedited rate of development and the limited funding for research are major impediments to peer-reviewed research into environmental impacts. Now is the time to work on these environmental issues to avoid an adverse environmental legacy similar to that from abandoned coal mine discharges in Pennsylvania.Fracturing Hydrology?
Hydraulic fracturing, widely known as "fracking," is a relatively inexpensive way to tap into what were previously inaccessible natural gas resources. Vidic et al. (p. 826) review the current status of shale gas development and discuss the possible threats to water resources. In one of the hotbeds of fracking activity, the Marcellus Shale in the eastern United States, there is little evidence that additives have directly entered groundwater supplies, but the risk remains. Ensuring access to monitoring data is an important first step toward addressing any public and environmental health concerns.Abstract
Unconventional natural gas resources offer an opportunity to access a relatively clean fossil fuel that could potentially lead to energy independence for some countries. Horizontal drilling and hydraulic fracturing make the extraction of tightly bound natural gas from shale formations economically feasible. These technologies are not free from environmental risks, however, especially those related to regional water quality, such as gas migration, contaminant transport through induced and natural fractures, wastewater discharge, and accidental spills. We review the current understanding of environmental issues associated with unconventional gas extraction. Improved understanding of the fate and transport of contaminants of concern and increased long-term monitoring and data dissemination will help manage these water-quality risks today and in the future.
Natural gas has recently emerged as an energy source that offers the opportunity for a number of regions around the world to reduce their reliance on energy imports or strive toward energy independence (1, 2). It may also be a potential transition fuel that will allow for the shift from coal to renewable energy resources while helping to reduce the emissions of CO2, criteria pollutants, and mercury by the power sector (3). The driving force behind this shift is that it has become economically feasible to extract unconventional sources of gas that were previously considered inaccessible. Conventional gas is typically extracted from porous sandstone and carbonate formations, where it has generally been trapped under impermeable cap-rocks after migration from its original source rock. In contrast, unconventional gas is usually recovered from low-permeability reservoirs or the source rocks themselves, including coal seams, tight sand formations, and fine-grained, organic-rich shales. Unconventional gas formations are characterized by low permeabilities that limit the recovery of the gas and require additional techniques to achieve economical flow rates (2).
The archetypical example of rapidly increasing shale gas development is the Marcellus Shale in the eastern United States (Fig. 1). Intensive gas extraction began there in 2005, and it is one of the top five unconventional gas reservoirs in the United States. With a regional extent of 95,000 square miles, the Marcellus is one of the world’s largest known shale-gas deposits. It extends from upstate New York, as far south as Virginia, and as far west as Ohio, underlying 70% of the state of Pennsylvania and much of West Virginia. The formation consists of black and dark gray shales, siltstones, and limestones (4). On the basis of a geological study of natural fractures in the formation, Engelder (5) estimated a 50% probability that the Marcellus will ultimately yield 489 trillion cubic feet of natural gas.Fig. 1 Marcellus Shale wells in Pennsylvania.
Rapid development of Marcellus Shale since 2005 resulted in more than 12,000 well permits, with more than 6000 wells drilled and ~3500 producing gas through December 2012 (average daily production ranged from <0.1 to >20 million cubic feet/day (MMCF/D). Current locations of centralized wastewater treatment facilities (CWTs) are distributed to facilitate treatment and reuse of flowback and produced water for hydraulic fracturing.
Concerns that have been voiced (6) in connection with hydraulic fracturing and the development of unconventional gas resources in the United States include land and habitat fragmentation as well as impacts to air quality, water quantity and quality, and socioeconomic issues (3, 5, 7). Although shale gas development is increasing across several regions of the United States and the world (such as the United Kingdom, Poland, Ukraine, Australia, and Brazil), this review focuses on the potential issues surrounding water quality in the Appalachian region and specifically the Marcellus Shale, where the majority of published studies have been conducted. Our Review focuses on chemical aspects of water quality rather than issues surrounding enhanced sediment inputs into waterways, which have been discussed elsewhere (4, 7, 8).Cause of the Shale Gas Development Surge
Recent technological developments in horizontal drilling and hydraulic fracturing have enabled enhanced recovery of unconventional gas in the United States, increasing the contribution of shale gas to total gas production from negligible levels in 1990 to 30% in 2011 (1). Although the first true horizontal oil well was drilled in 1929, this technique only became a standard industry practice in the 1980s (9). Whereas a vertical well allows access to tens or hundreds of meters across a flat-lying formation, a horizontal well can be drilled to conform to the formation and can therefore extract gas from thousands of meters of shale. Horizontal wells reduce surface disturbance by limiting the number of drilling pads and by enabling gas extraction from areas where vertical wells are not feasible. However, horizontal drilling alone would not have enabled exploitation of the unconventional gas resources because the reservoir permeability is not sufficient to achieve economical gas production by natural flow. Hydraulic fracturing—"hydrofracking," or "fracking"—was developed in the 1940s to fracture and increase permeability of target formations and has since been improved to match the characteristics of specific types of reservoirs, including shales.
Hydraulic fracturing fluids consist of water that is mixed with proppants and chemicals before injection into the well under high pressure (480 to 850 bar) in order to open the existing fractures or initiate new fractures. The proppant (commonly sand) represents generally ~9% of the total weight of the fracturing fluid (10) and is required to keep the fractures open once the pumping has stopped. The number, type, and concentration of chemicals added are governed by the geological characteristics of each site and the chemical characteristics of the water used. The fracturing fluid typically used in the Marcellus Shale is called slickwater, which means that it does not contain viscosity modifiers that are often added to hydrofracture other shales so as to facilitate better proppant transport and placement.
Chemical additives in the fluids used for hydraulic fracturing in the Marcellus Shale include friction reducers, scale inhibitors, and biocides (Table 1 and Box 1). Eight U.S. states currently require that all chemicals that are not considered proprietary must be published online (11), whereas many companies are voluntarily disclosing this information in other states. However, many of the chemicals added for fracturing are not currently regulated by the U.S. Safe Drinking Water Act, raising public concerns about water supply contamination. From 2005 to 2009, about 750 chemicals and other components were used in hydraulic fracturing, ranging from harmless components, including coffee grounds or walnut hulls, to 29 components that may be hazardous if introduced into the water supply (6). An inorganic acid such as hydrochloric acid is often used to clean the wellbore area after perforation and to dissolve soluble minerals in the surrounding formation. Organic polymers or petroleum distillates are added to reduce friction between the fluid and the wellbore, lowering the pumping costs. Antiscalants are added to the fracturing fluid so as to limit the precipitation of salts and metals in the formation and inside the well. Besides scaling, bacterial growth is a major concern for the productivity of a gas well (quantity and quality of produced gas). Glutaraldehyde is the most common antibacterial agent added, but other disinfectants [such as 2,2-dibromo-3-nitrilopropionamide (DBNPA) or chlorine dioxide] are often considered. Surfactants (alcohols such as methanol or isopropanol) may also be added to reduce the fluid surface tension to aid fluid recovery.Table 1
Common chemical additives for hydraulic fracturing.Box 1 Glossary of Terms
Casing: steel pipe that is inserted into a recently drilled section of a borehole to stabilize the hole, prevent contamination of groundwater, and isolate different subsurface zones.
Cementing: placing a cement mixture between the casing and a borehole to stabilize the casing and seal off the formation.
Class II disposal wells: underground injection wells for disposal of fluids associated with oil and gas production.
Flowback water: water that returns to the surface after the hydraulic fracturing process is completed and the pressure is released and before the well is placed in production; flowback water return occurs for several weeks.
Produced water: water that returns to the surface with the gas after the well is placed in production; production water return occurs during the life of a well.
Proppant: granular material, such as silica sand, ceramic media, or bauxite, that keeps the fractures open so that gas can flow to the wellbore.
Slickwater fracturing – fracturing with fluid that contains mostly water along with friction reducers, proppants, and other additives; used for predominantly gas-bearing formations at shallower depths.
Source rock - organic-rich sedimentary rocks, such as shale, containing natural gas or oil.
Stray gas - gas contained in the geologic formation outside the wellbore that is accidentally mobilized by drilling and/or hydraulic fracturing.Methane Migration
As inventoried in 2000, more than 40 million U.S. citizens drink water from private wells (12). In some areas, methane—the main component of natural gas—seeps into these private wells from either natural or anthropogenic sources. Given its low solubility (26 mg/L at 1 atm, 20°C), methane that enters wells as a solute is not considered a health hazard with respect to ingestion and is therefore not regulated in the United States. When present, however, methane can be oxidized by bacteria, resulting in oxygen depletion. Low oxygen concentrations can result in the increased solubility of elements such as arsenic or iron. In addition, anaerobic bacteria that proliferate under such conditions may reduce sulfate to sulfide, creating water- and air-quality issues. When methane degasses, it can also create turbidity and, in extreme cases, explode (13, 14). Therefore, the U.S. Department of the Interior recommends a warning if water contains 10 mg/L of CH4 and immediate action if concentrations reach 28 mg/L (15). Methane concentrations above 10 mg/L indicate that accumulation of gas could result in an explosion (16).
The most common problem with well construction is a faulty seal in the annular space around casings that is emplaced to prevent gas leakage from a well into aquifers (13). The incidence rate of casing and cement problems in unconventional gas wells in Pennsylvania has been reported previously as ~1 to 2% (17). Our count in Pennsylvania from 2008 to March 2013 for well construction problems [such as casing or cementing incidents (18)] cited by the Pennsylvania Department of Environmental Protection (DEP) revealed 219 notices of violation out of 6466 wells (3.4%) (19). Of these, 16 wells in northern Pennsylvania were given notices with respect to the regulation that the "operator shall prevent gas and other fluids from lower formations from entering fresh groundwater" (violation code 78.73A). Most of the time, gas leakage is minor and can be remedied. However, in one case attributed to Marcellus drilling and leaky well casings, stray gas that accumulated in a private water well exploded near the northeastern Pennsylvania town of Dimock. A study of 60 groundwater wells in that area, including across the border in upstate New York (20), showed that both the average and maximum methane concentrations were higher when sampled from wells within 1 km of active Marcellus gas wells as compared with those farther away. Much discussion has since ensued as to whether the methane detected in these wells was caused by drilling or natural processes (21–24) because the area has long had sources of both thermogenic and biogenic methane unrelated to hydraulic fracturing, and no predrilling baseline data are available. The averages reported in that study for sites both near and far from drilling are not dissimilar from values for groundwater from areas of Pennsylvania and West Virginia sampled by the U.S. Geological Survey (USGS) before the recent Marcellus Shale development began, or samples in New York state where high-volume hydrofracturing is currently banned (Fig. 2).Fig. 2 Methane concentrations in groundwater and springs.
(A) Published values for groundwater or spring samples include 239 sites in New York from 1999 to 2011 (84), 40 sites in Pennsylvania in 2005 (27), and 170 sites in West Virginia from 1997 to 2005 (85). Maxima varied from 68.5 mg/L in West Virginia, to 44.8 mg/L in Tioga County, Pennsylvania, where an underground gas storage field was leaking, to a value approaching 45 mg/L in New York. (B) Values shown with down arrows are averages for a set of wells in southeastern New York and northeastern Pennsylvania located <1 km (26 wells) and >1 km (34 wells) from active gas drilling (20).
The reason gas is found so often in water wells in some areas is because methane not only forms at depth naturally, owing to high-temperature maturation of organic matter, but also at shallow depths through bacterial processes (25, 26). Both these thermogenic and biogenic gas types can migrate through faults upward from deep formations or laterally from environments such as swamps (swamp gas) or glacial till (drift gas) (14, 27). In addition, gas can derive from anthropogenic sources such as gas storage fields, coal mines, landfills, gas pipelines, and abandoned gas wells (28). In fact, ~350,000 oil and gas wells have been drilled in Pennsylvania, and the locations of ~100,000 of these are unknown (29). Thus, it is not surprising that gas problems have occurred in Pennsylvania long before the Marcellus development (30). Pennsylvania is not the only state facing this problem because about ~60,000 documented orphaned wells and potentially more than 90,000 undocumented orphaned wells in the United States have not been adequately plugged and could act as vertical conduits for gas (31).
As natural gas moves in the subsurface, it can be partially oxidized, mixed with other gases, or diluted along flow paths. To determine its provenance, a "multiple lines of evidence approach" must be pursued (24). For example, researchers measure the presence of other hydrocarbons as well as the isotopic signatures of H, O, and C in the water or gas (16, 27, 31). Thermogenic gas in general has more ethane and a higher 13C/12C ratio than that of biogenic gas. Stable isotopes in thermogenic gas may sometimes even yield clues about which shale was the source of the gas (24, 32). In northeastern Pennsylvania, researchers argue whether the isotopic signatures of the methane in drinking-water wells indicate the gas derived from the Marcellus or from shallower formations (20, 24).
Although determining the origin of gas in water wells may lead to solutions for this problem, the source does not affect liability because gas companies are responsible if it can be shown that any gas—not just methane—has moved into a water well because of shale-gas development activity. For example, drilling can open surficial fractures that allow preexisting native gas to leak into water wells (13). This means that pre- and post-drilling gas concentration data are needed to determine culpability. Only one published study compares pre- and post-drilling water chemistry in the Marcellus Shale drilling area. In that study, a sample of 48 water wells in Pennsylvania investigated between 2010 and 2011 within 2500 feet of Marcellus wells showed no statistical differences in dissolved CH4 concentrations before or shortly after drilling (33). In addition, no statistical differences related to distance from drilling were observed. However, that study reported that the concentration of dissolved methane increased in one well after drilling was completed nearby, which is possibly consistent with an average rate of casing problems of ~3%.
The rate of detection of methane in water wells in northeast Pennsylvania [80 to 85% (20, 24)] is higher than in the wider region that includes southwestern Pennsylvania [24% (33)], where pre- and post-drilling concentrations were statistically identical. This could be a result of the small sample sizes of the two studies or because the hydrogeological regime in the northeast is more prone to gas migration (34). Such geological differences also may explain why regions of the Marcellus Shale have been characterized by controversy in regard to methane migration as noted above, whereas other shale gas areas such as the Fayetteville in Arkansas have not reported major issues with respect to methane (35). Reliable models that incorporate geological characteristics are needed to allow prediction of dissolved methane in groundwater. It is also critical to distinguish natural and anthropogenic causes of migration, geological factors that exacerbate such migration, and the likelihood of ancillary problems of water quality related to the depletion of oxygen. Answering some of these questions will require tracking temporal variations in gas and isotopic concentrations in groundwater wells near and far from drilling by using multiple lines of evidence (16, 24). Research should also focus on determining flow paths in areas where high sampling density can be attained.How Protective Is the "Well Armor"?
The protective armor shielding the freshwater zones and the surrounding environment from the contaminants inside the well consist of several layers of casing (hollow steel pipe) and cement (Fig. 3). When the integrity of the wellbore is compromised, gas migration or stray gas can become an issue (14). Gas migration out of a well refers to movement of annular gas either through or around the cement sheath. Stray gas, on the other hand, commonly refers to gas outside of the wellbore. One of the primary causes of gas migration or stray gas is related to the upper portion of the wellbore when it is drilled into a rock formation that contains preexisting high-pressure gas. This high-pressure gas can have deleterious effects on the integrity of the outer cement annulus, such as the creation of microchannels (36). Temperature surveys can be performed shortly after the cementing job is completed in order to ensure that cement is present behind the casing. Acoustic logging tools are also available to evaluate the integrity of the cement annulus in conjunction with pressure testing.Fig. 3 Typical Marcellus well construction.
(i) The conductor casing string forms the outermost barrier closest to the surface to keep the upper portion of the well from collapsing and it typically extends less than 12 m (40 ft) from the surface; (ii) the surface casing and the cement sheath surrounding it that extend to a minimum of 15 m below the lowest freshwater zone is the first layer of defense in protecting aquifers; (iii) the annulus between the intermediate casing and the surface casing is filled with cement or a brine solution; and (iv) the production string extends down to the production zone (900 to 2800 m), and cement is also placed in the annulus between the intermediate and production casing. Potential flaws in the cement annulus (Inset, "A" to "E") represent key pathways for gas migration from upper gas-bearing formations or from the target formation.
It is well known that to effectively stabilize wellbores with cement in areas with zones of overpressurized gas, proper cement design and proper mud removal are essential (37, 38). If the hydrostatic pressure of the cement column is not higher than the gas-bearing formation pressure, gas can invade the cement before it sets. Conversely, if this pressure is too high, then the formation can fracture, and a loss of cement slurry can occur. Even when the density is correct, the gas from the formation can invade the cement as it transitions from a slurry to a hardened state (39). The slurry must be designed to minimize this transition time and the loss of fluid from the slurry to the formation. Also, if drilling mud is not properly cleaned from the hole before cementing, mud channels may allow gas migration through the central portion of the annulus or along the cement-formation interface. Even if the well is properly cleaned and the cement is placed properly, shrinkage of the cement during hydration or as a result of drying throughout the life of the well can result in crack development within the annulus (40, 41).
Although the primary mechanisms contributing to gas migration and stray gas are understood, it is difficult to predict the risk at individual sites because of varying geological conditions and drilling practices. To successfully protect fresh water and the surrounding environment from the contaminants inside the well, the site-specific risk factors contributing to gas migration and stray gas must be better understood, and improvements in the diagnostics of cement and casing integrity are needed for both new and existing wells. Finding solutions to these problems will provide environmental agencies the knowledge needed to develop sound regulations related to the distances around gas wells that can be affected. It will also provide operators the ability to prevent gas migration and stray gas in a more efficient and economical manner.The Source and Fate of Fracturing Fluid
The drilling and hydraulic fracturing of a single horizontal well in the Marcellus Shale may require 2 million to 7 million gallons of water (42). In contrast, only about 1 million gallons are needed for vertical wells because of the smaller formation contact volume. Although the projected water consumption for gas extraction in the Marcellus Shale region is 18.7 million gallons per day in 2013 (39), this constitutes just 0.2% of total annual water withdrawals in Pennsylvania. Water withdrawals in other areas are similarly low, but temporary problems can be experienced at the local level during drought periods (3). Furthermore, water quantity issues are prevalent in the drier shale-gas plays of the southwest and western United States (43). It is likely that water needs will change from these initial projections as the industry continues to improve and implement water reuse. Nevertheless, the understanding of flow variability—especially during drought conditions or in regions with already stressed water supplies—is necessary to develop best management practices for water withdrawal (44). It is also necessary to develop specific policies regarding when and where water withdrawals will be permitted in each region (45).
After hydraulic fracturing, the pressure barriers such as frac plugs are removed, the wellhead valve is opened, and "flowback water" is collected at the wellhead. Once the well begins to produce gas, this water is referred to as "produced water" and is recovered throughout the life of the well. Flowback and produced waters are a mixture of injected fluids and water that was originally present in the target or surrounding formations (formation water) (42, 46–50). The fraction of the volume of injected water that is recovered as flowback water from horizontal wells in Pennsylvania ranges from 9 to 53% (9, 41), with an average of 10%. It has been observed that the recovery can be even lower than 10% if the well is shut-in for a period of time (51). The well is shut-in—or maintained closed between fracturing and gas production—so as to allow the gas to move from the shale matrix into the new fractures. Two of the key unanswered questions is what happens to the fracturing fluid that is not recovered during the flowback period, and whether this fluid could eventually contaminate drinking water aquifers (23, 33, 34, 52–54). The analyses of Marcellus Shale well logs indicate that the low-permeability shale contains very little free water (55, 56), and much of the hydraulic fracturing fluid may imbibe (absorb) into the shale.
Fracturing fluid could migrate along abandoned and improperly plugged oil and gas wells, through an inadequately sealed annulus between the wellbore and casing or through natural or induced fractures outside the target formation. Indeed, out-of-formation fractures have been documented to extend as much as ~460 m above the top of some hydraulically fractured shales (57), but still ~1.6 km or more below freshwater aquifers. Nonetheless, on the basis of the study of 233 drinking-water wells across the shale-gas region of rural Pennsylvania, Boyer et al. (33) reported no major influences from gas well drilling or hydrofracturing on nearby water wells. Compared with the pre-drilling data reported in that study, only one well showed changes in water quality (salt concentration). These changes were noticed within days after a well was hydrofractured less than ~460 m away, but none of the analytes exceeded the standards of the U.S. Safe Drinking Water Act, and nearly all the parameters approached pre-drilling concentrations within 10 months.
In the case of methane contamination in groundwater near Dimock, Pennsylvania, contamination by saline flowback brines or fracturing fluids was not observed (20). One early U.S. Environmental Protection Agency (EPA) report (54) suggested that a vertically fractured well in Jackson County, West Virginia, may have contaminated a local water well with gel from fracturing fluid. This vertical well was fractured at a depth of just ~1220 m, and four old natural gas wells nearby may have served as conduits for upward contaminant transport. A recent EPA study (53) implicated gas production wells in the contamination of deep groundwater resources near Pavillion, Wyoming. However, resampling of the monitoring wells by the USGS showed that the flowrate was too small to lend confidence to water-quality interpretations of one well, leaving data from only one other well to interpret with respect to contamination, and regulators are still studying the data (58). The Pavillion gas field consists of 169 production wells into a sandstone (not shale) formation and is unusual in that fracturing was completed as shallow as 372 m below ground. In addition, surface casings of gas wells are as shallow as 110 m below ground, whereas the domestic and stock wells in the area are screened as deep as 244 m below ground. The risk for direct contaminant transport from gas wells to drinking-water wells increases dramatically with a decrease in vertical distance between the gas well and the aquifer.
A recent study applied a groundwater transport model to estimate the risk of groundwater contamination with hydraulic fracturing fluid by using pressure changes reported for gas wells (52). The study concluded that changes induced by hydraulic fracturing could allow advective transport of fracturing fluid to groundwater aquifers in <10 years. The model includes numerous simplifications that compromise its conclusions (59). For example, the model is based on the assumption of hydraulic conductivity that reflects water-filled voids in the geological formations, and yet many of the shale and overburden formations are not water-saturated (60). Hence, the actual hydraulic conductivity in the field could be orders of magnitude lower than that assumed in the study (59). Furthermore, although deep joint sets or fractures exist (14), the assumption of preexisting1500-m long vertical fractures is hypothetical and not based on geologic exploration. Hence, there is a need to establish realistic flow models that take into account heterogeneity in formations above the Marcellus Shale and realistic hydraulic conductivities and fracturing conditions.
Last, it has long been known (14, 34, 47, 48, 61, 62) that groundwater is salinized where deeper ancient salt formations are present within sedimentary basins, including basins with shale gas. Where these brines are present at relatively shallow depths, such as in much of the northeastern and southwestern United States and Michigan, brines sometimes seep to the surface naturally and are unrelated to hydraulic fracturing. An important research thrust should focus on understanding these natural brine transport pathways to determine whether they could represent potential risk for contamination of aquifers because of hydraulic fracturing.Appropriate Wastewater Management Options
The flowback and produced water from the Marcellus Shale is the second saltiest (63) and most radiogenic (50) of all sedimentary basins in the United States where large volume hydraulic fracturing is used. The average amount of natural gas-related wastewater in Pennsylvania during 2008 to 2011 was 26 million barrels per year (a fourfold increase compared with pre-Marcellus period) (64). Compared with conventional shallow wells, Marcellus Shale wells generate one third of the wastewater per unit volume of gas produced (65). However, the wastewater associated with Marcellus development in 2010 and 2011 accounted for 68 and 79%, respectfully, of the total oil and gas wastewater requiring management in Pennsylvania. Flowback/produced water is typically impounded at the surface for subsequent disposal, treatment, or reuse. Because of the large water volume, high concentration of dissolved solids, and complex physical-chemical composition of this wastewater, which includes organic and radioactive components, the public is becoming increasingly concerned about management of this water and the potential for human health and environmental impacts associated with the release of untreated or inadequately treated wastewater to the environment (66). In addition, spills from surface impoundments (14) and trucks or infiltration to groundwater though failed liners are potential pathways for surface and groundwater contamination by this wastewater.
Treatment technologies and management strategies for this wastewater are constrained by regulations, economics of implementation, technology performance, geologic setting, and final disposal alternatives (67). The majority of wastewater from oil and gas production in the United States is disposed of effectively by deep underground injection (68). However, the state of Pennsylvania has only five operating Class II disposal wells. Although underground injection disposal wells will likely increase in number in Pennsylvania, shale gas development is currently occurring in many areas where Class II disposal wells will not be readily available. Moreover, permissions for and construction of new disposal wells is complex, time-consuming, and costly. Disposal of Pennsylvania brines in Ohio and West Virginia is ongoing but limited by high transportation costs.
The lack of disposal well capacity in Pennsylvania is compounded by rare induced low-magnitude seismic events at disposal wells in other locations (69–71). It is likely that the disposal of wastewater by deep-well injection will not be a sustainable solution across much of Pennsylvania. Nonetheless, between 1982 and 1984, Texas reported at most ~100 cases of confirmed contamination of groundwater from oilfield injection wells, saltwater pits, and abandoned wells, even though at that time the state hosted more than 50,000 injection wells associated with oil and gas (72). Most problems were associated with small, independent operators. The ubiquity of wells and relative lack of problems with respect to brine disposal in Texas is one likely explanation why public pushback against hydraulic fracturing is more limited in Texas as compared with the northeastern United States.
Another reason for public pushback in the northeast may be that in the early stages of Marcellus Shale development, particularly in 2008 to 2009, flowback/produced water was discharged and diluted into publicly owned treatment works (POTWs, or municipal wastewater treatment plants) under permit. This practice was the major pathway for water contamination because these POTWs are not designed to treat total dissolved solids (TDS), and the majority of TDS passed directly into the receiving waterways (6, 73), resulting in increased salt loading in Pennsylvania rivers, especially during low flow (74). In response, the Pennsylvania DEP introduced discharge limits to eliminate disposal of Marcellus Shale wastewater to POTWs (75). In early 2010, there were 17 centralized waste treatment plants (CWTs) in Pennsylvania that were exempted from the TDS discharge limits. However, according to Pennsylvania DEP records none of these CWTs reported to be currently receiving Marcellus wastewater, although they may receive produced water from conventional gas wells. Nevertheless, the TDS load to surface waters from flowback/produced water increased from ~230,000 kg/day in 2006 to 350,000 kg/day in 2011 (64).
It is difficult to determine whether shale gas extraction in the Appalachian region since 2006 has affected water quality regionally, because baseline conditions are often unknown or have already been affected by other activities, such as coal mining. Although high concentrations of Na, Ca, and Cl will be the most likely ions detected if flowback or produced waters leaked into waterways, these salts can also originate from many other sources (76). In contrast, Sr, Ba, and Br are highly specific signatures of flowback and produced waters (34, 47). Ba is of particular interest in Pennsylvania waters in that it can be high in sulfate-poor flowback/produced waters but low in sulfate-containing coal-mine drainage. Likewise, the ratio of 87Sr/86Sr may be an isotopic fingerprint of Marcellus Shale waters (34, 77).
Targeting some of these "fingerprint" contaminants, the Pennsylvania DEP began a new monitoring program in 2011. Samples are collected from pristine watersheds as well as from streams near CWT discharges and shale-gas drilling. The Shale Network is collating these measurements with high-quality data from citizen scientists, the USGS, the EPA, and other entities in order to assess potential water quality impacts in the northeast (78, 79). Before 2003, mean concentrations in Pennsylvania surface waters in counties with unconventional shale-gas development were 27 ± 32, 550 ± 620, and 72 ± 81 μg/L for Ba, Sr, and Br (±1σ), respectively (Fig. 4). Most values more than 3σ above the mean concentrations since 2003 represent samples from areas of known brine effluents from CWTs. A concern has been raised over bromide levels in the Allegheny River watershed that may derive from active CWTs because of health effects associated with disinfection by-products formed as a result of bromide in drinking water sources (64, 80). Given the current regulatory climate and the fact that the majority of dissolved solids passes through these CWTs, it is expected that these treatment facilities will likely not play a major role in Marcellus Shale wastewater management.Fig. 4 Concentrations of three ions in surface waters of Pennsylvania in counties with unconventional shale-gas wells: (A) barium, (B) strontium, and (C) bromide.
Data reported by EPA (STORET data), USGS (NWIS data), Susquehanna River Basin Commission, Appalachian Geological Consulting and ALLARM [from Shale Network database (78, 79)], and from the Pennsylvania DEP (SAC046) include all rivers, streams, ponds, groundwater drains, lysimeter waters, and mine-associated pit, seep, and discharge waters accessed by using HydroDesktop (www.cuahsi.org) in the relevant counties (data before 2009 for bromide are not shown). Lines indicate 3σ above the mean of data from 1960 to 2003 for the longest duration dataset (USGS). Most values above the lines since 2003 represent targeted sampling in areas of known brine effluents from conventional oil and gas wells (such as Blacklick Creek receiving brine effluent from a CWT). The highest plotted Ba concentration was measured in Salt Springs in northern Pennsylvania. Three of the four samples with highest Sr and Br are from Blacklick Creek; next highest is from Salt Springs. Original values reported beneath the detection limit are plotted at that limit (10 to 100 μg Sr/L; 10 μg Ba/L; and 10 to 200 μg/L Br). The EPA maximum contaminant level (MCL) for Ba is 2000 μg/L. EPA reports no MCL for Sr or Br. Lifetime and 1-day health advisory levels for Sr are 4000 and 25000 μg/L, respectively, and a level under consideration for Br is 6000 μg/L.
The dominant wastewater management practice in the Marcellus Shale region nowadays is wastewater reuse for hydraulic fracturing [a review of Pennsylvania DEP data for the first 6 months of 2012 indicates 90% reuse rate (81)]. Wastewater is impounded at the surface and used directly, or after dilution or pretreatment. Reuse of wastewater minimizes the volume that must be treated and disposed, thus reducing environmental control costs and risks and enhancing the economic feasibility of shale-gas extraction (67). Currently, operators in the Marcellus region do not fully agree about the quality of wastewater that must be attained for reuse. Major concerns include possible precipitation of BaSO4 and, to a lesser extent, SrSO4 and CaCO3 in the shale formation and the wellbore and the compatibility of wastewater with chemicals that are added to the fracturing fluid (such as friction reducers and viscosity modifiers). Hence, a better understanding of chemical compatibility issues would greatly improve the ability to reuse wastewater and minimize disposal volumes. In addition, radioactive radium that is commonly present in flowback/produced water will likely be incorporated in the solids that form in the wastewater treatment process and could yield a low-concentration radioactive waste that must be handled appropriately and has potential on-site human health implications.
The wastewater reuse program represents a somewhat temporary solution to wastewater management problems in any shale play. This program works only as long as there is net water consumption in a given well field. As the well field matures and the rate of hydraulic fracturing diminishes, the field becomes a net water producer because the volume of produced water will exceed the amount of water needed for hydraulic fracturing operations (82, 83). It is not yet clear how long it will take to reach that point in the Marcellus region, but it is clear that there is a need to develop additional technical solutions (such as effective and economical approaches for separation and use of dissolved salts from produced water and treatment for naturally occurring radioactive material) that would allow continued development of this important natural resource in an environmentally responsible manner. Considering very high salinity of many produced waters from shale gas development, this is truly a formidable challenge. Research focused on better understanding of where the salt comes from and how hydrofracturing might be designed to minimize salt return to the land surface would be highly beneficial.Conclusions
Since the advent of hydraulic fracturing, more than 1 million hydraulic fracturing treatments have been conducted, with perhaps only one documented case of direct groundwater pollution resulting from injection of hydraulic fracturing chemicals used for shale gas extraction (54). Impacts from casing leakage, well blowouts, and spills of contaminated fluids are more prevalent but have generally been quickly mitigated (17). However, confidentiality requirements dictated by legal investigations, combined with the expedited rate of development and the limited funding for research, are substantial impediments to peer-reviewed research into environmental impacts. Furthermore, gas wells are often spaced closely within small areas and could result in cumulative impacts (5) that develop so slowly that they are hard to measure.
The public and government officials are continuing to raise questions and focus their attention on the issue of the exact composition of the hydrofracturing fluid used in shale formations. In 2010, the U.S. House of Representatives directed the EPA to conduct a study of hydraulic fracturing and its impact on drinking-water resources. This study will add important information to account for the fate of hydraulic fracturing fluid injected into the gas-bearing formation. It is well known that a large portion (as much as 90%) of injected fluid is not recovered during the flowback period, and it is important to document potential transport pathways and ultimate disposition of the injected fluid. The development of predictive methods to accurately account for the entire fluid volume based on detailed geophysical and geochemical characteristics of the formation would allow for the better design of gas wells and hydraulic fracturing technology, which would undoubtedly help alleviate public concerns. Research is also needed to optimize water management strategies for effective gas extraction. In addition, the impact of abandoned oil and gas wells on both fluid and gas migration is a concern that has not yet been adequately addressed.
Gas migration received considerable attention in recent years, especially in certain parts of the Appalachian basin (such as northeast Pennsylvania). It has been known for a long time that methane migrates from the subsurface (such as coal seams, glacial till, and black shales), and the ability to ignite methane in groundwater from private wells was reported long before the recent development of the Marcellus Shale (14). However, in the absence of reliable baseline information, it is easy to blame any such incidents on gas extraction activities. It is therefore critical to establish baseline conditions before drilling and to use multiple lines of evidence to better understand gas migration. It is also important to improve drilling and cementing practices, especially through gas-bearing formations, in order to eliminate this potential pathway for methane migration.
Water management for unconventional shale gas extraction is one of the key issues that will dominate environmental debate surrounding the gas industry. Reuse of flowback and produced water for hydraulic fracturing is currently addressing the concerns regarding the vast salt quantities that are brought to the surface (each Marcellus well generates as much as 200 tons of salt during the flowback period). However, there is a need for comprehensive risk assessment and regulatory oversight for spills and other accidental discharges of wastewater to the environment. As these well fields mature and the opportunities for wastewater reuse diminish, the need to find alternative management strategies for this wastewater will likely intensify. Now is the time to work on these issues in order to avoid an adverse environmental legacy similar to that from abandoned coal mine discharges in Pennsylvania.References and Notes
S. Holditch, K. Perry, J. Lee, "Unconventional Gas Reservoirs—Tight Gas, Coal Seams, and Shales, Working Document of the National Petroleum Council on Global Oil and Gas Study" (National Petroleum Council, 2007).
S. M. Olmstead, L. A. Muehlenbachs, J.-S. Shih, Z. Chu, A. J. Krupnick, Proc. Natl. Acad. Sci. U.S.A., published online 11 March 2013.10.1073/pnas.1213871110doi:10.1073/pnas.1213871110
U.S. House of Representatives Committee of Energy and Commerce Minority Staff, "Chemicals used in Hydraulic Fracturing" (prepared for H. A. Waxman, E. J. Markey, D. DeGette, 2011).
Energy Information Administration, Drilling Sideways–A Review of Horizontal Well Technology and Its Domestic Application, DOE/EIA-TR-0565 (U.S. Department of Energy, Washington, DC, 1993).
NYS DEC, "Draft Supplemental Generic Environmental Impact Statement on the Oil, Gas and Solution Mining Regulatory Program, Well Permit Issuance for Horizontal Drilling And High-Volume Hydraulic Fracturing to Develop the Marcellus Shale and Other Low-Permeability Gas Reservoirs" (New York State Department of Environmental Conservation, 2009).
K. K. Eltschlager, J. W. Hawkins, W. C. Ehler, F. J. Baldassare, "Technical measures for the investigation and mitigation of fugitive methane hazards in areas of coal mining" (U.S. Dept. of the Interior, Office of Surface Mining Reclamation and Enforcement, Pittsburgh, PA, 2001).
T. Considine, R. Watson, N. Considine, J. Martin, "Environmental Impacts during Marcellus Shale Gas Drilling: Causes, Impacts, and Remedies, Report 2012-1" (Shale Resources and Society Institute, State University of New York, Buffalo, 2012).
K. J. Breen, K. Revesz, F. J. Baldassare, S. D. McAuley, "Natural gases in ground water near Tioga Junction, Tioga County, North-central Pennsylvania–Occurrence and use of isotopes to determine origins, 2005" (U.S. Geological Survey, Scientific Investigations Report Series 2007-5085, 2007).
PA DEP, "Oil and Gas Well Drilling and Production in Pennsylvania" (Pennsylvania Department of Environmental Protection, PA DEP Fact Sheet, 2011).
W. R. Gough, B. A. Waite, in Water Resources in Pennsylvania: Availability, Quality, and Management, S. K. Majumdar, E. W. Miller, R. R. Parizek, Eds. (Pennsylvania Academy of Science, 1990), pp. 384–398.
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M. E. Blauch, R. R. Myers, T. R. Moore, B. A. Lipinski, N. A. Houston, paper presented at the SPE Eastern Regional Meeting, Society of Petroleum Engineers SPE 125740, Charleston, WV, 2009.
E. L. Rowan, M. A. Engle, C. S. Kirby, T. F. Kraemer, "Radium content of oil- and gas-field produced waters in the Northern Appalachian Basin (USA): Summary and discussion of data" (U.S. Geological Survey, Scientific Investigation Report 2011-5135, 2011).
M. E. Mantell, in EPA Hydraulic Fracturing Study Technical Workshop 4. Water Resources Management, Chesapeake Energy (Oklahoma City, OK, 2011).
D. C. DiGiulio, R. T. Wilkin, C. Miller, G. Oberly, "DRAFT: Investigation of Ground Water Contamination near Pavillion, Wyoming" (U.S. Environmental Prodection Agency Office of Research and Development, 2011).
U.S. Environmental Protection Agency, "Report to Congress: Management of wastes from the exploration, development, and production of crude oil, natural gas, and geothermal energy" (U.S. Environmental Protection Agency, Washington, DC, 1987).
K. R. Bruner, R. A. Smosna, "Comparative study of the Mississippian Barnett Shale, Fort Worth Basin, and Devonian Marcellus Shale, Appalachian Basin, DOE/NETL-2011/1478" (Department of Energy, National Energy Technology Laboratory, 2011).
J. A. Williams, U.S. Geological Survey Scientific Investigations Report 2010-5224 (2010).
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C. J. de Pater, S. Baisch, "Geomechanical study of Bowland Shale seismicity, Synthesis Report" (Cuadrilla Resources, Ltd., 2011).
Reuters, "Ohio earthquake was not a natural event, expert says," Reuters, 2012.
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J. R. Mullaney, D. L. Lorenz, A. D. Arntson, "Chloride in Groundwater and Surface Water in Areas Underlain by the Glacial Aquifer System, Northern United States" (U.S. Department of the Interior, U.S. Geological Survey, Scientific Investigations Report 2009-5086, 2009).
S. States et al., paper presented at the AWWA-WQTC, Phoenix, AZ, November 13 to 17, 2011.
C. Kuijvenhoven et al., paper presented at the Shale Gas Water Management Conference, Dallas, TX, November 30 to December 1, 2011.
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J. S. White, M. V. Mathes, "Dissolved-gas concentrations in ground water in West Virginia" (U.S. Geological Survey Data Series 156, 2006).
Algeria is the leading natural gas producer in Africa, the second-largest natural gas supplier to Europe outside of the region, and is one of the top three oil producers in Africa. Algeria became a member of the Organization of the Petroleum Exporting Countries (OPEC) in 1969, shortly after it began oil production in 1958. Algeria’s economy is heavily reliant on revenues generated from its hydrocarbon sector, which account for about 25% of the country’s gross domestic product (GDP), more than 95% of export earnings, and 60% of budget revenues, according to the International Monetary Fund (IMF).1
Oil and natural gas export revenues amounted to $35.7 billion in 2015, down 41% from $60.3 billion in 2014.2 The average price for crude oil produced in Algeria in 2015 was $52.79 per barrel, down 47% from 2014. Foreign exchange reserves, which peaked at $194 billion in December 2013, tumbled to $153 billion in late 2015.3
Crude oil and gross natural gas production have gradually declined in recent years, mainly because of repeated project delays resulting from slow government approval, difficulties attracting investment partners, infrastructure gaps, and technical problems. In the past four licensing rounds, there was limited interest from investors to undertake new oil and natural gas projects under the government’s terms, awarding only 4 of 31 blocks in the 2014 bid round.4 An auction originally scheduled for late 2015 was canceled because of the failure of previous rounds.
Algeria (Figure 1)5 is estimated to hold the third-largest amount of shale gas resources in the world. The U.S. Energy Information Administration (EIA) estimates that Algeria contains 707 trillion cubic feet (Tcf) and 5.7 billion barrels of technically recoverable shale gas and oil resources, respectively. Some industry analysts are cautious about the prospects of Algeria becoming a notable shale producer. To develop these resources, Algeria will face many obstacles including the remote location of the shale acreage, the lack of infrastructure and accessibility to sites, water availability, the lack of roads and pipelines to move materials, and the need for more rigs because shale wells deplete quicker.
The 2013 militant attack on the In Amenas gas facility prompted security concerns about operating in Algeria’s remote areas, particularly in the south. Any major disruption to Algeria’s hydrocarbon production would not only be detrimental to the local economy but, depending on the scale of lost production, could affect world oil prices. Because Algeria is the second-largest natural gas supplier to Europe outside of the region, unplanned cuts to natural gas output could affect some European countries.6
Algeria relies on its own oil and natural gas production for domestic consumption, which is heavily subsidized. Natural gas and oil account for almost all of Algeria’s total primary energy consumption. Prices for oil products (diesel, gasoline, and liquefied petroleum gas) and natural gas in Algeria are among some of the cheapest prices in the world.7 The IMF estimates that the cost of the implicit subsidies on oil products and natural gas (both in the intermediary and final-use stages) amounted to $22.2 billion in 2012, or 10.9% of GDP.8 The 2016 budget law includes increased prices for gasoline, diesel, natural gas, and electricity for the first time in more than a decade as the Algerian government copes with falling revenue.9
Natural gas accounted for 93% of power generation in Algeria in 2013, according to the International Energy Agency (IEA).10 Algeria’s government is attempting to reduce the country’s dependence on natural gas in the power sector by increasing the share of electricity generated by renewable energy. However, even if Algeria’s share of renewables consumption increases, the country is still expected to increase its consumption of natural gas as well.
The Algerian Energy Ministry of Energy and Mines has set ambitious goals for electricity generation, aiming to generate 40% of Algeria’s electricity from renewable sources by 2030.11Energy sector management
Algeria’s national oil and natural gas company, Sonatrach, dominates the country’s hydrocarbon sector, owning roughly 80% of all hydrocarbon production. By law, Sonatrach is given majority ownership of oil and natural gas projects in Algeria.
Algeria’s oil and natural gas industries are governed by the Hydrocarbon Act of 2005. The initial legislation established terms that guided the involvement of international oil companies (IOCs) in upstream exploration and production, midstream transportation, and the downstream sector. The original 2005 legislation was more favorable to foreign involvement than its predecessor, which was passed in 1986. However, amendments to the bill were made in 2006, and some of the favorable terms were reversed. In the 2006 amendments, Algeria’s national oil company, Entreprise Nationale Sonatrach (Sonatrach), was granted a minimum equity stake of 51% in any hydrocarbon project, and a windfall profits tax was introduced for IOCs.
In recent years, Algeria has experienced difficulties attracting foreign investors, particularly at licensing rounds. In the most recent licensing round in 2014, only 4 of 31 blocks were awarded. Some analysts believe that the lack of fiscal incentives to attract foreign investors to new projects, coupled with past Sonatrach corruption allegations, were to blame. Algeria’s precarious security environment has also been a concern for investors.
In 2013, Algeria revised parts of the hydrocarbon law in an attempt to attract foreign investors to new projects. Amid declining hydrocarbon production and stagnant reserves, the Algerian government has stated it needs foreign partners to increase oil and natural gas reserves and explore new territories, such as offshore in the Mediterranean Sea and onshore areas containing shale oil and natural gas resources. The 2013 amendments introduced a profit-based taxation, as opposed to revenue-based taxation and lowered tax rates for unconventional resources. The amendments also allow for a longer exploration phase for unconventional resources (11 years compared to 7 years for conventional resources) and a longer operating/production period of 30 years and 40 years for unconventional liquid and gaseous hydrocarbons, respectively (compared to 25 years and 30 years for conventional liquids and gas, respectively). The amendments, however, do not change Sonatrach’s mandated role as a majority stakeholder in all upstream oil and natural gas projects.12
Sonatrach owns roughly 80% of total hydrocarbon production in Algeria, while IOCs account for the remaining 20%, based on data from Rystad Energy. IOCs with notable stakes in oil and natural gas fields are: Cepsa (Spain), BP (United Kingdom), Eni (Italy), Repsol (Spain), Total (France), Statoil (Norway), and Anadarko (United States). Sonatrach’s substantial assets in Algeria make it the largest oil and natural gas company not only in the country, but also in Africa. The company operates in several parts of the world, including: Africa (Mali, Niger, Libya, Egypt), Europe (Spain, Italy, Portugal, United Kingdom), Latin America (Peru), and the United States.Security risks
Militant groups operating in North Africa and the Sahel have presented security risks to oil and natural gas installations in the region. In January 2013, a militant group stormed Algeria’s In Amenas gas facility, resulting in several causalities and a temporary suspension of natural gas production at the facility.
Concerns over Algeria’s security environment resurfaced on January 16, 2013 when a militant group attacked the In Amenas gas facility (Figure 2)13, resulting in several worker and militant causalities. The attack reportedly damaged two of the facility’s three processing trains, each of which has the capacity to process 3 billion cubic meters per year (Bcm/y), or 106 billion cubic feet per year (Bcf/y). Natural gas output at In Amenas was first partially restarted at the end of February 2013 at one of the three trains with the second train returning to service two months later. The third train is still out of service, but is expected to restart in 2016.14The In Amenas gas facility in Algeria Source: BP
The In Amenas gas processing facility, located near the Libyan border, is jointly operated by Sonatrach, BP, and Statoil. After the incident occurred, BP and Statoil withdrew their staff from In Amenas and the In Salah gas facility (located 373 miles to the west of In Amenas), setting back plans to boost output at both projects.
Natural gas output at In Amenas averaged 6.1 Bcm/y through September 2015.15 Prior to the attack, In Amenas output averaged 7.8 Bcm/y (or 275 Bcf/d) of dry natural gas, accounting for almost 10% of Algeria’s dry natural gas production and almost 16% of exports in 2012.16 Natural gas plant liquids (NGPL) are also produced at the In Amenas fields and averaged 43,400 barrels per day (b/d) in 2012, although nameplate capacity is around 60,000 b/d, according to MEES.17 Despite the absence of some personnel, production at In Salah remained relatively unchanged at 8.2 Bcm/y (290 Bcf/y) in 2013, compared with the previous year.Petroleum: Reserves and exploration
Algeria holds the third-largest amount of proved crude oil reserves in Africa, all of which are located onshore because there has been limited offshore exploration. According to Sonatrach, about two-thirds of Algerian territory remains largely underexplored or unexplored.
According to the latest Oil & Gas Journal estimates released in January 2016, Algeria held an estimated 12.2 billion barrels of proved crude oil reserves, an estimate that has been unchanged for many years.18 All of the country’s proved oil reserves are held onshore because there has been limited offshore exploration. Most proved oil reserves are in the country’s oldest and largest oil field, Hassi Messaoud, located in the eastern part of the country, near the Libyan border. Hassi Messaoud is estimated to hold 3.9 billion barrels of proved and probable recoverable reserves, followed by the Hassi R’Mel field (3.7 billion barrels) and the Ourhoud field (1.9 billion barrels), according to the Arab Oil & Gas Directory.19
According to Sonatrach, roughly two-thirds of Algerian territory remains underexplored or unexplored. Most of these areas are in the north and offshore. There is potential to expand oil production in areas that have already been exploited as well, particularly in the Hassi Messaoud, Illizi, and Berkin basins. According to Sonatrach, the Hassi Messaoud-Dahar province contains about 71% of the country’s combined proved, probable, and possible oil reserves, while the Illizi basin, the second-largest area, contains about 15%. The Illizi and Berkine basins have been home to many discoveries since the 1990s and still hold significant potential.20Production and development
Algeria produced almost 1.7 million b/d of total petroleum and other liquids in 2015, which includes crude oil, condensate, natural gas plant liquids, and refinery processing gain.
Algeria produced an estimated average of 1.1 million b/d of crude oil in 2015 (Figure 3), slightly lower than the previous year. Combined with almost 600,000 b/d of noncrude oil liquids, which are not included in its OPEC quota, Algeria’s total oil production averaged almost 1.7 million b/d in 2015.
Algerian oil fields produce high-quality light crude oil with very low sulfur content. Sonatrach operates the largest oil field in Algeria, Hassi Messaoud, which typically produces 500,000 b/d of crude oil, or more than 40% of Algeria’s total crude output.21 Other large producing areas in Algeria include the Ourhoud and the Hassi Berkine complex. Algeria’s largest oil fields are mature. Field expansions and enhanced oil recovery techniques have kept the country’s oldest fields at a steady rate of production, but this trend is slowly starting to reverse. As a result, EIA projects that Algeria’s crude oil output will gradually decline at least in the short and medium term.
Algeria does not have any major crude oil projects scheduled to come onstream. There are smaller oil projects scheduled to come onstream (Timimoun), along with additional output from existing fields (Gassi Touil-Rhoude Nouss and Hassi Messaoud), but the amount of production is expected to fall short of what is needed to offset natural decline rates at older fields.
The latest notable fields to start production were El Merk and Bir Seba. Production started at El Merk in early 2013, and output of crude oil, condensate, and liquefied petroleum gas (LPG) averaged roughly 135,000 b/d in 2015.22 Bir Seba production came online in October 2015, producing 20,000 b/d with a goal of reaching 40,000 b/d by 2020.23 Although new production is coming online in these fields, the new volumes will only partially offset declines in other existing fields.Crude oil exports
Most (about 76%) of Algerian crude oil exports are sent to Europe.
Algeria exports mostly light crude oil. The country’s main crude grade is the Sahara blend, which is a blend of crudes produced at fields in the Hassi Messaoud region. In 2015, Algeria exported approximately 540,000 b/d of crude oil, including condensate, according to EIA estimates based on Lloyd’s List Intelligence (APEX tanker tracking). Most of Algeria’s crude oil exports are sent to Europe (76%), with the remainder sent to the Americas (17%) and Asia and Oceania (7%) (Figure 4) .24
The United States was one of Algeria’s largest markets for crude oil for almost a decade until 2013. U.S. crude oil imports from Algeria have substantially declined in recent years. The United States imported 31,000 b/d of crude oil from Algeria in 2015, which is down from its peak of 443,000 b/d in 2007. The growth in U.S. light, sweet crude oil production from the Bakken and Eagle Ford shale plays has resulted in a sizable decline in U.S. imports of crude grades of similar quality, like Algeria’s crude oil.Refined petroleum products
Algeria has five oil refineries with a total nameplate capacity of about 523,000 b/d. Most of Algeria’s domestic petroleum consumption, which is estimated to have averaged 433,000 b/d in 2015, derives from domestically refined products. Algeria’s petroleum consumption has increased by an annual average of 6% over the past decade.
Algeria has five oil refineries with a total nameplate capacity of 522,800 b/d (Table 1)25, according to the Oil & Gas Journal.26 The country’s largest refinery, Skikda, is located along Algeria’s northern coastline, and it is the largest refinery in Africa. The refinery has the capacity to process 355,300 b/d of crude oil and condensate, accounting for more than half of Algeria’s total refinery capacity. Skikda processes the Saharan blend, which derives from the Hassi Messaoud oil fields. Algeria’s two other coastal refineries, Algiers and Arzew, have the capacity to process 58,100 b/d and 75,000 b/d, respectively. The country’s inland refineries, Hassi Messaoud and Adrar, are connected to local oil fields and supply oil products to nearby areas.
Most of Algeria’s domestic petroleum consumption, which averaged 433,000 b/d in 2015, derived from domestically refined products. Algeria’s petroleum consumption has increased by an annual average of 6% over the past decade (2006 to 2015). Algeria typically produces a surplus of refined petroleum products, which is exported to global markets. From January 2015 to November 2015, the United States imported an average of 108,000 b/d of refined products from Algeria.Table 1: Oil refineries in Algeria Refinery Capacity (000 b/d) Type Owner Skikda 355 Crude oil/ condensate Sonatrach/Naftec Hassi Messaoud 22 Crude oil Sonatrach/Naftec Algiers (El Harrach) 58 Crude oil Sonatrach/Naftec Arzew 75 Crude oil Sonatrach/Naftec Adrar 13 Crude oil CNPC Total 523 Note: CNPC is the China National Petroleum Company. Source: Oil & Gas Journal Oil pipelines and export terminals
Algeria uses multiple coastal terminals to export crude oil, refined products, LPG, and NGPL. These facilities are located at Arzew, Skikda, Algiers, Annaba, Oran, and Bejaia in Algeria and La Skhirra in Tunisia. Algeria’s domestic pipeline network facilitates the transfer of oil from interior production fields to coastal infrastructure. The most important pipelines carry crude oil from the Hassi Messaoud field to refineries and export terminals. Algeria does not have any transcontinental export oil pipelines.Natural gas: Reserves and exploration
Algeria holds the world’s eleventh-largest amount of proved natural gas reserves and the third-largest technically recoverable shale gas resources. In May 2014, Algeria’s Council of Ministers gave formal approval to allow shale oil and shale gas development.
According to Oil & Gas Journal, as of January 2016, Algeria had 159 trillion cubic feet (Tcf) of proved natural gas reserves, the eleventh-largest natural gas reserves in the world and the second-largest reserves in Africa, behind Nigeria. Algeria’s largest natural gas field, Hassi R’Mel, was discovered in 1956. Located in the center of the country to the northwest of Hassi Messaoud, it holds proved reserves of about 85 Tcf, more than half of Algeria’s total proved natural gas reserves. According to the Arab Oil & Gas Directory, Hassi R’Mel accounted for three-fifths of Algeria’s gross natural gas production in 2012. The remainder of Algeria’s natural gas reserves are located in associated and nonassociated fields in the southern and southeastern regions of the country.27
Algeria also holds vast untapped shale gas resources. According to an EIA-sponsored study released in June 2013, Algeria contains 707 Tcf of technically recoverable shale gas resources, the third-largest amount in the world after China and Argentina. The Ghadames Basin, encompassing eastern Algeria, southern Tunisia, and western Libya, was identified as a major shale gas basin in the assessment. In May 2014, Algeria’s Council of Ministers gave formal approval to allow shale oil and shale gas development. The Council of Ministers estimated that it would take 7 to 13 years to confirm Algeria’s potential shale resources.Production and development
Algeria’s gross natural gas production was 6.6 Tcf in 2014, a 4% increase from the previous year. Production has steadily declined over the past decade as output from the country’s large, mature fields is depleting. There are several new projects planned to come online, but they have repeatedly been delayed.
Algeria’s gross natural gas production was 6.6 Tcf in 2014, a 4% increase from the previous year (Figure 5). Algeria’s gross production had been falling since its peak of 7.1 Tcf in 2008. The increase in 2014 reflects the return of lost production at the In Amenas gas facility.
In 2014, 45% (2.9 Tcf) of gross natural gas production was marketed, 43% (2.9 Tcf) was reinjected into wells to enhance oil recovery, and 2% (0.1 Tcf) was vented or flared. Dry natural gas production (a subcategory of marketed gas that occurs when associated liquid hydrocarbons are removed) was 3.0 Tcf in 2014, of which 1.3 Tcf was consumed locally and approximately 1.5 Tcf was exported.
Algeria has been planning to bring on stream several new natural gas fields to compensate for the loss of production from mature fields, but many of these projects have been delayed by several years, mostly because of delayed government approval, difficulties attracting investment partners, infrastructure gaps, and technical problems (Table 2)28.Table 2: Upcoming natural gas projects in Algeria Project Name Companies Peak output (Bcf/y) 1 Target start year South West Gas Project: Phase 1 Touat Engie/Sonatrach 155 2016 Reggane Nord Repsol/Sonatrach/DEA/Edison 155 2017 Timimoun Total/Sonatrach/Cepsa 64 2017 South West Gas Project: Phase 2 Ahnet Total/Sonatrach/Partex 141 2018 Hassi Ba Hamou Sonatrach 64 — Hassi Mouina Sonatrach 49 2018 Other gas projects In Salah (expansion)2 BP/Sonatrach 500 2016 Isarene (Ain Tsila) Petroceltic/Sonatrach/Enel 127 2018 Tinhert, Illizi basin Sonatrach 332 2018 Menzel Ledjmet SE Sonatrach 155 2019 1Billion cubic feet per year is Bcf/y.2Field expansion at In Salah is to ensure that the current level of output at In Salah is maintained. Source:Middle East Economic Survey
Algeria is in the process of developing its Southwest Gas Project, which includes Reggane Nord and Timimoun, which are expected to start production three years behind schedule in 2017, and Touat, which is scheduled to come online in 2016. The Repsol-led Reggane Nord project consists of developing six fields and is expected to reach a peak production rate of 155 Bcf/y.29 The Timimoun project, led by Total in partnership with Sonatrach and Cepsa, is expected to reach a peak production of 64 Bcf/y, and the Touat project is projected to reach a peak production of 155 Bcf/y.30 The Southwest Gas Project entails the construction of natural gas-gathering facilities, a natural gas treatment plant, and a pipeline to the Hassi R’Mel gas hub, called the GR5 pipeline. The planned infrastructure will connect the remote Southwest natural gas fields to the Hassi R’Mel region and allow for the commercialization of other fields in the south as well. The development and commercialization of the Ahnet natural gas project in the south will also depend on the new infrastructure.
The Southwest Gas Project is very important for Algeria’s ability to meet contracted exports and its expected growth in domestic demand. Gross natural gas production in the country will most likely continue to steadily decline in the short term, but it may recover in the medium term if planned projects come online and offset natural declines. Output from the Southwest Gas Project and other proposed projects (some of which are not included in the table) have the potential to increase Algeria’s output by 1 Tcf/y or more after 2018. However, these projects are contingent on attracting investors and building new infrastructure or upgrading older infrastructure.Midstream and downstream infrastructure
Algeria exports natural gas via pipelines and on tankers in the form of liquefied natural gas (LNG). The country has three transcontinental export natural gas pipelines: two transport natural gas to Spain and one transports natural gas to Italy. Algeria’s LNG plants are located in the coastal cities of Arzew and Skikda. Algeria was the first country in the world to export LNG in 1964.Domestic pipelinesAlgeria’s domestic natural gas pipeline system transports natural gas from the Hassi R’Mel fields and processing facilities, owned by Sonatrach, to export terminals and liquefaction plants along the Mediterranean Sea. There are three main domestic pipeline systems: Hassi R’Mel to Arzew, Hassi R’Mel to Skikda, and Alrar to Hassi R’Mel. The Hassi R’Mel to Arzew system is a collection of pipelines that move natural gas from Hassi R’Mel to the export terminal and the LNG plant at Arzew. The system also includes an LPG pipeline. The Hassi R’Mel to Skikda system transports natural gas from the Hassi R’Mel fields to the Skikda LNG plant, and the Alrar to Hassi R’Mel system transports natural gas produced in the Alrar and the southeastern region to the Hassi R’Mel processing facilities. Sonatrach is building the GR5 Southwest fields to the Hassi R’Mel pipeline to monetize natural gas reserves in fields discovered in southwestern Algeria.
Transcontinental pipelinesAlgeria has three transcontinental export natural gas pipelines: two transport natural gas to Spain and one transports natural gas to Italy (Table 3)31. The largest pipeline, Pipeline Enrico Mattei (GEM), came online in 1983 and runs 1,025 miles from Algeria to Italy via Tunisia. GEM’s capacity is more than 1.3 Tcf/y and it is jointly owned by Sonatrach, the Tunisian government, and Eni. The Pedro Duran Farell (GPDF) pipeline started in 1996 and travels 325 miles to Spain via Morocco. GPDF’s capacity is about 390 Bcf/y. The newest pipeline, MEDGAZ, came online in 2011 and is owned by Sonatrach, Cepsa, Endesa, Iberdrola, and GDF Suez. MEDGAZ stretches 125 miles onshore and offshore, from Algeria to Spain via the Mediterranean Sea.Planned transcontinental pipelines
Algeria plans to develop two additional transcontinental export pipelines, although both projects have suffered delays, and it is highly uncertain whether both pipelines will be built. The Gasdotto Algeria Sardegna Italia (GALSI) pipeline is planned to transport natural gas to Italy via a pipeline with a subsea section. Initially, its capacity is expected to be 282 Bcf/y. The pipeline project has gone through feasibility studies, and there are concerns about logistics, costs, pricing formulas, and long-term contractual commitments. The Trans-Saharan Gas Pipeline (TSGP) is proposed to run slightly more than 2,600 miles to deliver natural gas from Warri, Nigeria to Algeria (via Niger), which will then link to the MEDGAZ route to Spain, although this link may be changed in the future. However, security concerns about militant groups across remote areas in the Sahel, in addition to growth constraints to Nigerian natural gas production, have presented considerable downside risks to investors interested in financing the project.Liquefied natural gas (LNG) plants
Algeria became the world’s first LNG producer in 1964 when the Arzew LNG facility came online. In 2014, Algeria was the world’s seventh-largest exporter of LNG, exporting about 5% of the world’s total exports. Algeria has four liquefaction LNG units located along the Mediterranean Sea at Arzew and Skikda, with a total design capacity to process 44 Bcm per year of natural gas.32Table 3: Algeria’s transcontinental natural gas pipelines Pipeline name Start year Route Length (miles) Capacity (Bcf/y) Pipeline Enrico Mattei (GEM) 1983 Algeria to Italy via Tunisia 1,025 1,340 Pedro Duran Farell pipeline (GPDF) 1996 Algeria to Spain via Morocco 325 390 MEDGAZ Pipeline 2011 Algeria to Spain via the Mediterranean Sea 125 280 Total export pipeline design capacity 2,010 Proposed pipelines GALSI Pipeline — Algeria to Italy 534 282 Trans-Saharan Gas Pipeline (TSGP) — Nigeria to Algeria via Niger 2,602 706 -1,059 Billion cubic feet per year is Bcf/y. Source: Sonatrach, IHS Cera, and Cedigaz Natural gas exports
Algeria exported about 1.5 Tcf of natural gas in 2014. Approximately 90% of Algeria’s natural gas exports were sent to Europe in 2014, making it the region’s second-largest natural gas supplier.
Algeria exported approximately 1.5 Tcf of natural gas in 2014, of which approximately 910 Bcf was transported via pipelines and 578 Bcf by LNG tankers.33 Algeria is Europe’s second-largest natural gas supplier outside of the region, after Russia. In 2014, more than 87% of Algeria’s pipeline exports were sent to European countries, and the remainder was sent to Morocco and Tunisia as payment in lieu of transit fees (Figure 6)34. Also, 84% of Algeria’s LNG exports were sent to Europe with the remainder going to markets in Asia and Oceania.35
Algeria’s natural gas exports have gradually declined over the past decade, as gross production decreases and domestic consumption increases. Despite new LNG export infrastructure and increased capacity, Algeria’s LNG exports have declined over the past few years, although an increase in production in 2014 led to an increase in exports as well. Algeria is facing pressure to boost natural gas output with new projects to meet growing domestic demand and to fulfill long-term contractual obligations to export natural gas to Europe.Electricity
Algeria’s public utility, Sonelgaz, is pursuing a large-scale investment program to almost double electricity generation capacity in the next few years. However, Sonelgaz faces some challenges as energy subsidies continue to affect its finances and as natural gas output has declined. Most of Algeria’s planned capacity additions are from natural gas-fired power plants.
Algeria’s electricity generation capacity reached 15.2 gigawatts (GW) at the end of 2014, up from 12.9 GW at the end of 2012 and 11.4 GW at the end of 2011, according to Sonelgaz, the country’s public utility in charge of electricity generation and distribution.36 Sonelgaz brought additional capacity online to keep up with demand needs. In the past, Sonelgaz imposed rationing to balance electricity supply and demand. In 2012, the government enforced power cuts that provoked public protest in the summer months.
Net electricity consumption was 45 billion kilowatthours in Algeria in 2014. Algeria’s electricity consumption has increased by an annual average of roughly 8% from 2008 to 2014. Most generation capacity comes from natural gas-fired and combined-cycle power plants, although the share of renewable energy in Algeria’s generation mix is growing but still limited. According to the Electricity and Gas Regulation Commission (CREG), the country’s electricity and natural gas market regulator, the national electricity system consists of an interconnected network that distributes power to northern and southern parts of the country. About 99% of Algeria’s population is connected to the national grid.
Algeria’s power demand peaks during the summer months and reached a new peak of 12.4 GW in August 2015.37 Sonelgaz plans to add more than 12 GW of generating capacity by 2017–18. The focus of the generation expansions are eight combined cycle gas turbine (CCGT) power plants to total 10 GW, which began commissioning in 2015. Algeria also added 256 MW of solar capacity in 2015, which is part of a 400-megawatt (MW) solar capacity program that started in 2013.38 Also, Sonelgaz commissioned a 12 turbine, 10 MW wind farm at Adrar in 2014, which is a pilot project for a wind capacity program that plans to bring 639 MW online by 2023.39 The Algerian Ministry of Energy and Mines has set ambitious goals for electricity generation, aiming to generate 40% from renewable sources by 2030.40
One of Sonelgaz’s main challenges is the ability to finance new generation projects amid fixed electricity prices, which have an impact on the company’s finances. Additionally, energy subsidies in Algeria have resulted in budget deficits. Another challenge is natural gas supply. Most of Algeria’s planned capacity additions are natural gas-fired units; meanwhile, Algeria’s gross natural gas production has been declining as new projects slated to boost output have repeatedly been delayed.
1International Monetary Fund, “IMF Country Report: p26 (February 2014); Middle East Economic Survey, “Algeria’s Oil & Gas Revenues Plunge 41% in 2015” (January 29, 2016), volume 59, issue 4.2Middle East Economic Survey, “Algeria’s Oil & Gas Revenues Plunge 41% in 2015” (January 29, 2016), volume 59, issue 4.3Ibid.4Middle East Economic Survey, “Algeria: Sonatrach Re-Engages With IOCs In Race Against Upstream Decline” (December 23, 2015), volume 58, issue 52.5U.S. Department of State6CEDIGAZ7International Monetary Fund, 2013 Article IV Consultation (2014)8International Monetary Fund, 2013 Article IV Consultation (2014)9Middle East Economic Survey, “Algeria Ratifies 2016 Budget Despite Opposition” (December 4, 2015), volume 58, issue 49.10International Energy Agency11Algerian Ministry of Energy and Mines, Renewable Energy and Energy Efficiency Program, page 4.12Middle East Economic Survey, “Algeria Fleshes Out New Oil Law” (January 11, 2013), volume 56, issue 2.13BP14Middle East Economic Survey, “Start-Up Imminent At 500mn Cfd In Salah Southern Fields” (January 8, 2016), volume 59, issue 1.15Ibid.16Ibid.17Ibid.18Oil & Gas Journal, Worldwide Reserves 201619Arab Oil & Gas Directory, www.stratener.com, Algeria (2014), p26 (subscription required)20Sonatrach21Arab Oil & Gas Directory, www.stratener.com, Algeria (2014), p26 (subscription required)22Middle East Economic Survey, “Algeria’s Upstream Challenges in Four Graphs” (July 31, 2015), volume 58, issue 31.23PTTEP24Lloyd’s List Intelligence (APEX Tanker Tracking)25Oil & Gas Journal, Worldwide Refining Survey 201626Ibid.27Arab Oil & Gas Directory, www.stratener.com, Algeria (2014), p31 (subscription required)28Middle East Economic Survey, “Algeria’s Upstream Investment: Running To Stand Still” (May 29, 2015), volume 52, issue 22.29Ibid.30Ibid.31Sonatrach, CEDIGAZ, IHS Cera32Sonatrach33CEDIGAZ (subscription required)34Ibid.35Ibid.36Middle East Economic Survey, “Algeria’s Peak Power Demand Soars, New Capacity Starting Up” (November 6, 2015), volume 58, issue 45.37Middle East Economic Survey, “Algeria’s Peak Power Demand Soars, New Capacity Starting Up” (November 6, 2015), volume 58, issue 45.38Ibid.39Middle East Economic Survey, “Can Algeria Live Up To Its Renewable Potential?” (April 3, 2015), volume 58, issue 14.40Algerian Ministry of Energy and Mines, Renewable Energy and Energy Efficiency Program, page 4.
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