According to a 2014 U.S. Energy Information Agency (EIA) forecast, U.S. unconventional natural gas production from shale formations will double by 2035 to generate about half of the total domestic natural gas production. At the same time, domestic oil production from unconventional shale formations was projected to increase by as much as 15% over the next several decades.
This boom in production combined with recent advances in modern horizontal drilling technology and fracking has unlocked vast U.S. shale reserves. The technology has stirred much controversy, spurring protests from environmental groups and residents of communities in active shale production areas.
To address the concerns of communities and environmentalists, the American Petroleum Institute (API) created 130 standards referenced in more than 430 citations by government agencies. Many of the innovations in hydraulic fracturing have been developed to meet those standards. The scenario has been complicated recently by the oil price crash of 2014, which inspired even more innovations by producers. Developments occurring mostly since that crash are addressed in this article.
Although the first horizontal well was drilled in 1929, it’s only been in the last decade that advanced materials and drilling technologies have made it possible for operators to drill horizontally for a mile or more through a rock formation.
Advances have made extraction less expensive because each horizontal well reaches a much larger rock volume than the several wells drilled to develop a reservoir in vertical drilling. Horizontal wells also can significantly delay problems with vertical methods that lead to lower production and recovery efficiencies, as well as premature abandonment of wells. This is because horizontal wells tap into a much greater percentage of the reserve. Since the plays are horizontal in the strata, by drilling along the horizontal, more of the natural gas or oil can be tapped. When drilling vertically, only the small portion of the horizontal reserve that is intersected by the vertical bore can be tapped.
After the oil price crash of 2014, producers needed to refine the technology even further to bring costs down while meeting new industry challenges.
Lynn Helms1 in his paper, “Horizontal Drilling,” calls this development the second generation of horizontal drilling: operators, and drilling and service contractors have devised, tested and refined procedures, as well as designed and put into place improved equipment. The result is that displacements of over 8,000 feet are now achievable. It also is now possible to drill stratigraphic traps, heterogeneous reservoirs and coal beds. As a result, older fields can be drilled to boost recovery factors. Examples of second generation applications are Cedar Hills-Red River and Wiley-Madison in North Dakota.
There is now a third generation of this equipment, which Helms says attains much longer, deeper and more accurate placement of multiple horizontal well bores to exploit fractured source rocks, and heat injection wells such as those used in Canadian oil sands steam-assisted gravity drainage. The present middle Bakken play in North Dakota and eastern Montana is an example of third-generation horizontal drilling.
When Kent Perry, executive director, E&P Research at Gastechnology Institute (GTI), is asked what he considers the most important advances in making fracturing profitable, he points to several improvements. “Producers are moving toward higher proppant loading [the solid material, typically sand, that is designed to keep induced hydraulic fractures open], along with changes in spacing between perforations,” he says. Also, the longer horizontal wellbores are being fractured, “growing to as much as three miles in length,” he says.
Another advancement includes casing the well [putting sections in tubing for reinforcement] into the producing formation during drilling of the horizontal section. This allows operators to use lower density drilling mud. Helms notes that, “They can even allow the well to produce during drilling operations, preventing much of the formation damage that normally occurs when mud density must be high enough to keep well bore pressure greater than formation pressures.”
These technological achievements have enabled smaller operators to maximize returns from each well. However, major drillers are now borrowing even more sophisticated technology from offshore operations.
One example is Shell’s “iShale” initiative. The company is using sensors to automatically adjust the flow of wells and control the separation of natural gas, oil and water. Such systems are very expensive when used offshore. But Shell is looking to incorporate low-cost sensors such as those used in the Apple Watch. The idea is to use the sensors to eliminate the need for workers to be onsite at drilling rigs. The sensors could allow several wells to be overseen by workers from one place, reducing costs and making the best use of assets. Also, failures could be predicted, and repairs scheduled accordingly.
According to Perry, this is a step that companies such as Shell, Schlumberger and others are taking toward complete automation of the drilling process. Schlumberger, for example, has tested controlling well drilling in the U.S. from overseas as part of its research. “Complete automation is not yet possible for drilling a well due to many variables that require human intervention, but a considerable portion of the drilling process is now automated,” Perry says.
He adds that, “The most significant change in this area is the ability to collect and process large volumes of data.” 3D and 4D seismic readings and logs from large numbers of wells and other places contribute to collecting this “big data,” while computer modeling, data management and new information technology assist in analyzing it.
Combinations of technological advancement from many industries such as the auto industry and the space program, which use robotics, are contributing to this data mining and use. Information technology advancements such as artificial intelligence can process and make decisions that will instruct the robotics. Data transfer via the internet and other channels enables monitoring and viewing of the processes.
Perry also notes that long horizontal wellbores have introduced some additional challenges to what’s done. “One in particular that requires additional research is production techniques that keep fluids moving through the long horizontal wellbore as flow rates decrease with time,” he says.
A complication is that oil and water tend to lay in low spots within the wellbore, which decreases production, he says. “The ability to determine exactly where production is coming from in a horizontal well is needed,” he says. While production logs can be run to help answer such questions, collecting that data is not practical from a cost and operational perspective, he adds.
Another challenge for producers is detecting leaks in pipelines and monitoring tanks. One solution is drone technology, which makes it possible to scan huge swaths of land with numerous wells using thermal imaging. This cuts down on the costs of manual inspections and possible costly shutdowns.
The ability to accurately predict the best places to drill also has proven vexing. To that end, advanced down-hole sensors have been developed and used to map the location of underground fractures in horizontal wells.
Also, Perry says that even though there are new methods to detect resources, producers must be able to assimilate and process the data created. This data provides input into geologic models that then provide more clarity on formation properties, he says.
One example of this at work comes from ConocoPhillips, which plans to start using magnetic resonance imaging in 2019 to analyze Permian rock samples and find the best drilling locations. The technology is not new to the industry; the company first used it for its offshore Alaska operations. However, with modern advances in analyzing the data, the results can provide better finding capabilities.
Oil companies are also using another interesting technology borrowed from medicine: DNA sequencing. Anadarko and Statoil are using sequencing to pinpoint areas that have promising potential. Sequencing works by collecting DNA from the microbes in oil, which is then used to search for the same DNA in rock samples.
ConocoPhillips is working with service providers on better accuracy and more control in the fracturing process itself. The company is looking at determining how to put greater pressure on the junctions between vertical and horizontal wellbores. With greater pressure, drillers can more effectively stimulate a fracture. According to Ryan Lance, chief executive of ConocoPhillips, this multi-lateral technology is the next breakthrough that will change hydraulic fracturing in the U.S.
Another promising innovation is laser energy. GTI has performed research using this energy instead of mechanical tools or explosives to perforate wells, which means lasers could drill the wells instead of the standard rotating drill pipe and drill bit method. Perry says that, though a commercial product is not yet available, the research shows promise.
Whether horizontal or vertical fracking is used, one of the biggest issues facing drillers and operators is water. The issues involve the fact that scarce fresh water is used in the process as well as what to do with the produced water (the water trapped and brought to the surface along with oil or gas).
Global estimates are that three barrels of water are produced for every barrel of crude oil taken from the ground. The longer the well is produced, the more water goes into the process: In North America, the ratio approaches 10:1.
Produced water has several ingredients beyond the oil and grease that comes from the well. Those include salt, bacteria and other organisms, inorganic salts, dissolved or dispersed hydrocarbons, dissolved gases (such as H2S and CO2), and chemicals. Those chemicals are naturally occurring as well as what’s used in the fracking process including oxygen scavengers, scale inhibitors, emulsion breakers and clarifiers, coagulants, flocculants and solvents.
According to Kent, a large portfolio of technologies is under development for water processing, including membrane research, osmosis, vaporization and others.
All have challenges for commercial use including the demand for water that occurs in an area under development and what happens when the development moves to a new area.
“Each well changes significantly in the volume of water produced, and the quality of the water can change as well. It is not like a municipal water treatment situation where the location and other criteria are somewhat stable,” Kent explains.
The primary treatment technologies for water produced from the well include using gravity oil and water separators, phase separations, dissolved air floatation, chemical treatment and distillation. Electrochemical methods also exist, including electrodialysis and electrofloatation. More recently, electrocoagulation is being explored, and some studies indicate this method has the capability of removing most of the water contaminants present in oily wastewater and produced water.3
GTI has a water-based life cycle model that can assess water needs. It simulates the water needs over the lifetime of a field under development. Inputs include how many wells are drilled over time, how much water each well requires, how much water comes from local sources and from produced water, what portion of the produced water can be processed based on its quality, what the cost is for doing so and more. The model identifies the water needed over time and identifies periods of excess water availability and times where more water is needed from some other sources.
Obtaining fresh water has become increasingly difficult for fracking operations for several reasons, so water treatment, recycling, disposal and reuse will continue to be top-of-mind challenges for producers even as technology to drill and produce becomes more sophisticated.
Over the long term, the ability to resolve the issue of fresh water use and produced water disposal will be a main influence on unconventional oil and gas production. While it seems nothing on the horizon can replace horizontal drilling because of its importance to the world of oil and gas, the direction and future of hydraulic fracturing will depend on improvements to that process.
- Lynn Helms, DMR Newsletter, Vol. 35, No. 1
The Trump Administration:
Litigation Burdens Efforts to Ease Regulatory Burdens
By Wayne D’Angelo and Jordan A. Rodriguez
A year into his presidency, President Trump has sought to repeal multiple environmental regulations enacted during the Obama Administration. Among the most significant milestones in 2017 were: (1) the Bureau of Land Management’s (BLM) rule to limit venting, flaring and leakage of natural gas from operations on federal and tribal lands; (2) the BLM’s repeal of rules for hydraulic fracturing on federal and tribal lands; and (3) the U.S. Environmental Protection Agency’s (EPA) reconsideration of new source performance standards (NSPS) for methane emissions for the oil and gas sector.
Each action finds its roots in the March 28, 2017 Executive Order 13783, titled “Promoting Energy Independence and Economic Growth.” The order directed a wholesale restructuring of major federal actions to regulate greenhouse gas emissions and climate change impacts, and directed EPA to review, rescind or rewrite the Obama Administration’s Climate Action Plan and associated methane emission standards for the oil and gas sector. It also revoked several previous executive actions, including guidance on calculating the social costs of greenhouse gas emissions and accounting for those emissions in environmental reviews, as well as a moratorium on federal coal leasing. Finally, the order directed all federal agencies to review existing regulations that unnecessarily burden domestic energy production, and to recommend ways to alleviate or eliminate those burdens.
When President Trump issued EO 13783, Congress seemed poised to send the President a congressional review act (CRA) resolution rescinding BLM’s Methane and Waste Prevention Rule (one of four Department of the Interior regulations targeted in the executive order). This rule was created to “reduce the waste of natural gas from flaring, venting, and leaks from oil and gas production operations on public and Indian lands” and requires operators to pay royalties on wasted gas. Six weeks later, the Senate failed to secure a simple majority in support of the CRA resolution.
With its failure, the Administration was forced to act unilaterally. BLM quickly announced it would excuse companies from complying with parts of the rule that had not yet taken effect, and environmental groups challenged the decision just as quickly. The Northern District of California struck down the delay of the rule on Oct. 4, and BLM appealed the decision to the Ninth Circuit two months later.
To meet the environmental group’s successful challenge to BLM’s informal delay of the rule, EPA also formally promulgated a rule in December delaying many of the rule’s provisions until July 2019. Once again, a coalition of environmental groups sued BLM. The states of New Mexico and California also sued BLM over its decision to delay the rule. Both lawsuits, filed in the Northern District of California, remain pending at press time (California and New Mexico v. BLM 3:17-cv-07186 and Sierra Club v. BLM 3:17-cv-07187).
Like the methane and waste rule, BLM’s effort to roll back Obama Administration regulations of hydraulic fracturing on public and tribal lands has taken some strange turns. This rule sought to update BLM’s program for federal land and minerals development to ensure protection of drinking water, with focus on requiring disclosure of the chemicals used in fracking. A federal court in Wyoming struck down the Obama-era rule in 2016 and thus it has never taken effect. Proponents of the rule appealed to the U.S. Court of Appeals for the Tenth Circuit where government attorneys directed by Trump appointees delicately defended the BLM’s authority to regulate fracking on federal and tribal lands but urged the court not to rule because BLM was reconsidering the issue. The Tenth Circuit agreed to halt the litigation in light of the new administration’s decision to reconsider the rule. When the Tenth Circuit issued its decision, however, it also vacated the Wyoming court’s injunction against implementing the rule. Therefore, on Dec. 29, BLM was forced to repeal the regulations through formal rulemaking procedures. Nearly a month later, California’s attorney general and several environmental groups filed a lawsuit over the repeal. (California v. BLM 3:18-cv-00521 (N.D. Cal.); Sierra Club v. BLM 3:18-cv-00524 (N.D. Cal.)). At press time, this case also remains pending.
SUING THE EPA
EPA also has been sued over its attempts to delay or repeal methane NSPS for the oil and gas sector. Earlier EPA standards indirectly limited methane pollution from new natural gas wells and some upstream sources, but this is the first rule to target methane emissions across the natural gas value chain. It also requires methane pollution control at oil wells, where co-produced natural gas is often vented and burned off. On June 5, EPA granted a petition for reconsideration of key provisions of the methane standards and delayed (for three months) implementation of key provisions of the rule. On the very same day, environmental groups challenged the reconsideration and delay. (Clean Air Council et al. v. Pruitt, Case No. 17-1145 (D.C. Cir.)).
In July, the D.C. Circuit sided with the challengers, vacated EPA’s delay and then granted a two-week stay with the admonition that any further delay would be seen as “arbitrary, capricious, [and] … in excess of [EPA’s] statutory … authority.” The court reasoned that EPA could only legally delay the effective date of a formal agency rule by undertaking a new formal agency rulemaking (with opportunities for public review and comment). EPA initiated that rulemaking process in November when it issued and took comments on two Notices of Data Availability providing new information on EPA’s authority to stay the rule. Comments were due Dec. 8, and the rule remains in effect pending EPA’s publication of a final modified rule.
While EPA’s final action likely will moot the environmental group’s suit over the delay of the methane standard, other groups are already teeing up new litigation. In August, environmental groups announced they would sue EPA for not regulating methane emissions from existing oil and gas infrastructure, arguing that once a final rule for new sources is issued, EPA is obligated to set methane standards for existing sources. If successful, this approach could require methane emissions regulation from all existing oil and gas infrastructure in the United States.
As these actions show, the Trump Administration’s aggressive approach to deregulation in 2017 has been met by environmental groups’ equally aggressive use of litigation. While the environmental groups were successful in 2017, their successes largely forced the Administration to abide by rulemaking procedures that it arguably overlooked in its desire for swift reform. The decisions made in these cases do not invalidate or otherwise limit the substance of the Administration’s actions, however. Thus, the Trump Administration likely will continue to pursue the same deregulatory goals throughout 2018, but with more careful observance of regulatory procedures.