Managing drilling and production wastes is one of the most critical areas of concern for oil and natural gas upstream operations today.
During the past 2 decades, D&P wastes have come under increased scrutiny for their environmental impact from governments and regulators around the world. Authorities have come to question the waste disposal practices of industry in the past and now demand that industry step up efforts to better minimize, contain, and safely dispose of wastes in order to avoid harm to ecosystems.
As those efforts accelerate, industry in the past few years also has experienced sharply rising service and supply costs owing to a general lack of personnel and capacity to handle operators’ needs. Consequently, the costs of managing D&P wastes have risen as well.
The soaring costs of rehabilitating old, abandoned oil and gas operations sites also raise the specter of what industry’s future liability will be if it doesn’t handle its waste streams wisely. Beyond the actual costs of future legal liability and attendant clean-up costs, a poor track record in this area could threaten industry’s future access to untapped oil and gas resources in the future. As more traditional producing areas deepen their decline, the industry will, of necessity, move increasingly into environmentally sensitive areas. Demonstrating an inability keep its waste streams from causing environmental damage thus would bode ill for oil and gas companies seeking to replace their reserves.
Consequently, the upstream industry is fashioning a new waste management paradigm that approaches as an ideal a near-zero surface discharge standard. One of the hottest areas in oil and gas research and development today is a focus on new technologies and processes that can push D&P waste management closer to that standard.
US regulatory concerns
Managing D&P wastes comes under the purview of a number of federal and state regulatory regimes in the US.
Relevant federal regulations are implemented by US Environmental Protection Agency, Bureau of Land Management, and Minerals Management Service. The most critical of these regulatory regimes is the exemption of D&P wastes from the hazardous waste requirements of Subtitle C of the Resource Conservation and Recovery Act (RCRA) that EPA established in 1988. Losing this exemption would be devastating to the US oil and gas industry by sharply escalating D&P costs, creating orders-of-magnitude increases in permitting delays, and straining the nation’s hazardous waste disposal capacity.
Most industry experts queried for this supplement concurred that the outlook is positive for industry retaining the RCRA exemption for E&P wastes.
“I don’t think the exemption is in any danger of being eliminated,” says William A. Piper, of Stafford, Tex.-based drilling environmental issues consultant Piper Consulting. “Certain portions of E&P waste may be examined and determined to be nonexempt, but the major fractions will remain exempt.”
Two executives with Halliburton Inc.’s Baroid Fluid Services division, Simon Seaton, Baroid Surface Solutions global operations manager, and John Hall, Baroid global environmental specalist, weigh in jointly with their view that the prospects for retaining the RCRA exemption are good: “The reason for this is that the E&P industry has a very good track record of managing what generally are low-hazard, high-volume waste streams.”
Piper also cites concerns over the federal Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), the so-called Superfund law. “Theoretically, following RCRA rules would avoid creating any CERCLA (Superfund) sites, but the E&P industry must remain aware that generators, transporters, disposers, treaters, handlers, etc. of waste materials could become potential responsible parties…in CERCLA clean-ups.”
Reg Minton, vice-president of waste management business development at Houston-based M-I Swaco, contends that EPA “appears to have a number of issues on its plate that are more critical than reclassifying E&P wastes.
“A refocusing on this classification will only occur in the near term if the industry draws public attention to this issue. It is up to us to act responsibly and ensure we understand the consequences of our decisions.
John Veil, with Argonne National Laboratory in Washington, DC, thinks that at the state level there could be future isolated efforts to narrow or remove the RCRA excemption to reflect local politics and policy, “but I am not aware that such a situation is currently imminent.
“The cost of managing the vast volumes of E&P waste in ways that are more like the EPA’s hazardous waste program would cripple domestic production and offer minimal environmental benefit. There is no strong driving force of which I am aware that would move the governments toward such a questionable endpoint.”
William F. Werdenberg, CEO of US Liquids of Louisiana LP (USLL), notes that Louisiana and Texas support EPA’s exemption for D&P waste but nevertheless are encouraging oil and gas companies to recycle wastes.
“USLL is actively working with state agencies to classify properly treated and processed E&P waste as a ‘recycled product’ for reuse in supporting vegetation, road base, levee fill, and land reclamation,” he says. “In November of 2005, USLL proposed rule changes to the Railroad Commission of Texas for the recycling of E&P waste streams into a reusable road base product. We also proposed that the new rules provide a release from liability for generators once the waste has been properly treated.”
The commission agreed to stipulate in the rulemaking that an E&P waste stream that has been converted into a recyclable product meeting well-defined criteria will not be classified as a waste, according to Werdenberg.
“Once approved, this new regulation will have a positive impact on drilling operations and will enable a recycling culture to emerge and therefore eliminate this waste stream in the future.”
Future regulatory concerns
Several experts fretted about future liability in managing D&P wastes. Minton contends that little consideration is given to future liabilities in relation to current waste disposal practices:
“For example, did anyone factor in the potential cost of recovering cuttings piles from the North Sea when deciding to discharge overboard?”
New regulations covering newly contentious areas also could emerge. Piper cites onshore regulations addressing salt content in disposal as one potentially difficult hurdle.
Minton adds to the list the problem of managing LSA (low specific activity) scale and naturally occurring radioactive material (NORM), “undeniably an issue that has to be dealt with, but it is not an issue the industry has actively attempted to address.”
Veil says he does not expect major, sweeping changes to regulatory requirements for drilling wastes or NORM.
“Over time, as permits are renewed, the EPA will most likely add more tiers of requirements onto existing requirements,” he says. “At some point operators may feel that the cost of complying with those permits are prohibitive and will look toward other E&P waste management options.”
Nontechnical challenges
Piper contends that waste-reporting techniques need to be standardized.
“Across the industry, we do a poor job at quantifying how much waste is generated, what is done with it, and how much it costs,” he says. “Without this information, investigation into alternate options and analysis of the impact of those options is subject to personal bias or preconception.”
Another area where challenges will arise are those regions that are considered extremely sensitive, notes Veil, “where there is little margin for error in handling water and waste and where the footprints of onsite facilities are likely to be minimal.”
Seaton voices his concerns about the lack of industry waste management infrastructure:
“Globally, some of the biggest challenges facing the industry are the lack of availability of landfill and other traditional waste disposal facilities, coupled with rising costs and environmental impacts of transport,” he says. “This is compounded by exploration and production activities moving into increasingly remote locations. Because of the distances involved in the transport of wastes and lack of infrastructure in these new frontiers, R&D needs to focus on two main areas:
• “During the drilling process, there is a need for cost-effective treatment at the rig site to recover as much drilling fluid from cuttings as possible. Recovery for reuse is highly desirable, since this reduces fluid consumption and associated transport, and the reclamation of drilling fluid also significantly reduces the waste volumes to be transported off location and eventually disposed of. Halliburton recently acquired a new cuttings drying technology for this purpose.
• ”Drilling and production waste that can be disposed of safely in situ does not need to be transported. Further R&D is ongoing into the modeling and the monitoring of subsurface waste injection so that regulators and operators gain greater confidence that sufficient volumes of waste can be safely and permanently contained.”
Reducing wastes
Industry has made significant strides in reducing waste volumes simply by virtue of its improvements in drilling efficiencies.
In the US, the volumes of drilling muds and drill cuttings generated per barrel of new oil and gas reserves added fell to 3.4 bbl of waste/BOE of reserves added in 1989-95 from 7.5 bbl/BOE in 1978-82. Much of this decline owes to improvements in seismic technology and increased use of horizontal and other directional drilling, which together have reduced the number of wells needed to add an equivalent volume of reserves added compared with past practices.
In addition, slimhole and coiled tubing drilling is gaining acceptance in the industry, which also helps reduce waste volumes. A slimhole well drilled to 14,760 ft at bottom with 4½-inch casing generates one fourth less volume of drill cuttings than a standard well drilled to the same depth.
Enhanced drilling efficiencies can even pose a problem for managing drilling wastes, according to Hall:
“Operators have been focused on and had considerable success in accelerating their drilling rates,” he says. “It is important to design a drilling waste management system that can accommodate these increasing drill rates to ensure that the handling and processing of drill cuttings does not become a bottleneck in the operation.”
Oil and gas operators still have room for improvement in terms of source reduction and recycling of drilling waste.
The key isn’t simply to minimize waste but to do it cost-effectively, says Piper.
“A well cannot be drilled without creating some waste, although people advocating reuse of cuttings might argue that point. There are several ways to view effectiveness. Certainly from a current-cost basis, burial and discharge are effective, which is why these methods are so frequently practiced. Cost may be difficult to assess, though.”
In a sense, there will always be an end-of-pipe solution for some wastes where source reduction is not possible.
“This solution may be disposal or reuse, but drill cuttings waste is an absolute result of drilling a hole in the ground,” Piper notes. “It is important for the industry to understand that even with ‘closed-loop,’ a large amount of drill cuttings will still be generated.”
Outside recycling
Recycling outside of D&P operations may prove the ultimate solution as source reduction and internal recycling reach their practical limits.
“Affordable source reduction on land and offshore may be years in the future, but recycling drilling and production wastes is economical today,” claims Werdenberg. “Land treatment, processing, and disposal ranges from $6/bbl to $12/bbl. Complement that process with recycling into road base or levee fill, and you can understand how cost-effective and efficient land treatment and recycling can be even with the transportation cost added in.”
His company’s land treatment technology affords such a solution.
“Land treatment is a proven and effective method to clean oil field waste by removing oil and chlorides, which are the primary contaminants in this waste stream,” Werdenberg says. “Most other methodologies on the Gulf Coast focus on disposing of waste in municipal landfills or injecting waste into the subsurface. The best method to eliminate this waste stream is to turn it into a useful product that can be reused in society.”
USLL’s R3 (reduce, reuse, and recycle) initiative is seen as an opportunity to potentially eliminate industry’s liability for D&P waste treatment.
With the new process, soluble salt content is decreased, oil concentration is reduced by recovery or degradation, and clean cuttings can be converted into environmentally friendly reuse and recycle products.
But Werdenberg considers the real challenge here to be regulatory.
“The real end-of-pipe issue today is getting regulatory agencies to release the producer from cradle-to-grave liability issues when cuttings are properly treated, processed, and converted into clean reuse products like road base and levee fill.
“Independent lab tests confirm that with R3 treatment technology clean reuse material can be converted into high-performance road base that is cleaner and more affordable than asphalt and has higher compressive strength. Given the large volume of road base consumed, all of the cuttings produced in the Gulf Coast region can be economically converted to road base and levee material with zero environmental impact.”
USLL is seeking E&P company support for its reuse initiatives through its R3 Sponsorship Program for Gulf Coast and South Texas operators.
“Participating E&P sponsors will benefit from helping us work with regulators to ensure that the reuse and recycling applications we’re implementing will help eliminate E&P operator liability in the future.
“As with any technology change in our industry, it will take some time to demystify the land treatment R3 process. What’s important for operators and regulators to realize is that land treatment by a professional waste management contractor dedicated to this important aspect of the business is more cost-effective than wellsite burial.
“This process also eliminates the risks associated with disposal through high-pressure pumping of waste into slurry injection wells and prevents E&P waste from being comingled with municipal waste at commercial landfills, as is currently practiced in the industry.”
In such efforts to find an end use for residual drilling waste-in particular oil- or synthetic-based cuttings-Seaton and Hall see an opportunity for the next game-changing technology in managing D&P wastes.
“The goal is that these residues are no longer considered a waste stream but instead are a valuable product or a raw material for another process,” they say. “For example, Halliburton is assisting a cement manufacturer with the blending of oil-based drill cuttings with other raw materials they currently use to create a new, alternative raw material in the cement manufacturing process. This has the added environmental benefit of reducing the consumption of other resources.”
It’s also important for operators to remember that, in assessing the cost-effectiveness of waste minimization, they must also look to the issues of industry’s long-term liability and public image.
“Inevitably, there will be diminishing returns from ever more sophisticated approaches to waste minimization,” Minton says. “However, as part of the economic analysis, potential longer-term liabilities have to be taken into account.
“The industry also needs to consider how performance in one area could permit access to other, environmentally sensitive areas. There should also be more effort invested in improving the way the public perceives the industry. That objective could be achieved in part by effecting remedial steps to minimize the impact drilling operations have on the environment. Taking these factors into account would allow for a true economic evaluation of various decisions that are made today on the basis of strictly quantifiable local costs.”
Slow take-up of technology is part of the problem as well, according to Minton:
“Technology exists to materially reduce waste generation, separate, and recycle valuable elements from the waste streams, and as a result, minimize the waste that ultimately requires disposal. However, industry inertia delays the adoption of viable technologies. This is compounded because few operators are able to evaluate the true value of new technologies, as they have little data reflecting the actual cost of waste collection, transportation, treatment, and disposal.”
Innovative approaches
Taking the long view demonstrates a key part of the new waste management paradigm that is evolving in the industry.
This new paradigm centers on taking a more holistic approach to waste management.
“The most effective approach is to integrate drilling fluid, solids control and drilling waste management activities,” Hall says. “These services are so intimately linked that to manage them as separate functions will never full realize the synergies possible. This concept of total fluids management services, correctly applied, has been proven globally to optimize operational, economical, and environmental performance.”
At the same time, tailored solutions are needed, says Minton: “One of the most important things to consider when prescribing an approach to managing drilling muds and cuttings is that the unique characteristics of a project need to be taken into account. A customized solution is always preferable to a cookie-cutter approach.”
In evaluating some of the most effective approaches employed, Minton says that cuttings slurrying and reinjection has proven to be the most cost-effective solution for waste disposal in development drilling operations where the number of wells being drilled is greater than four or five.
“Problems have been encountered with reinjection operations because of well plugging or unexpected fracture propagation. So, the key to successful implementation of this technology is the use of a proper assurance process that focuses on the quality of the slurry being prepared and the actual behavior of the fracture in the subsurface formations.”
For oil-contaminated cuttings, onshore thermal desorption optimizes the capacity of the installed equipment base and ensures the recovered oil can be recycled for use, Minton points out: “When thermal desorption is combined with the use of chloride-free, oil-based muds, the cleaned cuttings can be used for landscaping, rather than having to be landfilled.”
One innovative solution for onshore treatment is the use of vermiculture. This entails blending oily cuttings organic waste, with specific species of worms added to the piles. The organic waste and oily cuttings are ingested by the worms. The resulting material is a high-grade soil enhancer/compost.
“Crucially, the material now has value and can be sold on, rather than being a waste,” notes Minton.
Another value-added approach is a combination of demulsification technology and mechanical processes recently deployed in Indonesia to effectively process complex refinery wastes, Minton says: “The process achieved disposal pit closure, and the receipts from the sale of the recovered oil more than covered the costs associated with the treatment processes.”
New business practices
Changes in business practices between operating and service companies are needed to optimize waste management practices, according to Minton.
“For me, the biggest game-changer will be revolutionizing the contracting environment so that business drivers for the operating and service companies are aligned, rather than being diametrically opposed, which is often the case at present.
“I would like to see contract awards that recognize the interrelationships of the various services required, awards that are driven by meaningful key performance indicators. In this way, all of the players are facing the same direction.
Minton contends that, in business terms, there is an active disincentive to efficient fluids and waste management.
“Issuing separate contracts for drilling fluid services, solids control equipment, and waste management means that no one has overall accountability for optimized solutions. In fact, the more efficient the service companies are, the less revenue and profit they realize.
Combined contracts of this nature, dubbed Integrated Fluid Engineering (IFE) contracts, have been demonstrated to materially reduce waste generated from drilling operations while often reducing the overall outlays on these combined services, according to Minton.
“In Austria, IFE delivered a 43% reduction in the volume of drilling waste generated by the fourth year of implementation, compared with the historical average,” he notes. “In Hungary, the reduction was 43% by the third year of implementation.”
Minton also decries the reticence to invest in new technology in the business.
“To a large extent, operating companies have withdrawn from drilling-related technology research (including waste treatment and processing), leaving the service industry to don the mantle of technology development. The service companies are closer to the front line and are often more cognizant of the opportunities for technology developments. On the other hand, the risk-averse nature of our business means that the adoption of new technology often occurs at a snail’s pace.
“Because the drilling team’s performance is based on the costs of the last well drilled, there is little incentive to take the risks associated with adopting new technology. Every operator wants to be the second to use a technically innovative solution, but few want to be the first.
“It can be 10 years before a specific technology is widely adopted, which leaves the service company holding the bag in terms of R&D costs. From a business standpoint, this delay in recovering a return on investment takes much of the business incentive away from the companies that lead the industry in terms of technology innovation.
Nevertheless, Minton contends that “the push toward environmental excellence will continue.
“I believe excellence can be achieved by aligning operator and service company business drivers.