UPSTREAM OPERATIONS PRODUCERS MODIFY ACTIVITIES AS THREAT OF NEW RULES LOOMS

Guntis Moritis
Production Editor

U.S. oil and gas field operators are modifying production activities to comply with the diverse nature of environmental regulations.

The industry's planning and environmental auditing procedures for meeting the current regulations are in place. But implementation needs time for training people, redesigning processes, and installing equipment that lessen environmental risks.

Complicating industry's compliance are the many federal and state rules that are still evolving.

Two widely cited publications that clarify the enacted regulations are the 1989 API document1 dealing with the federal level and the 1990 Interstate Oil Compact Commission (IOCC) study2 that compiles the rules in each state.

Many arguments still exist on how safe is safe, and how clean is clean, but the consensus in the oil and gas industry is that states should have primacy in regulating exploration and production (E&P) wastes. Its position is that E&P operations are too diverse in geology, hydrology, climate, and waste characteristics to be cost effectively regulated by one set of rules from the federal government.

Industry also does not want technology to drive the environmental standards. Even though new technology allows measuring more minute quantities of a substance, this in itself does not justify changing standards unless the lower quantities prove to be damaging. One of industry's current concerns is the scheduled reauthorization of the Resource Conservation Recovery Act of 1976 (RCRA).

The 1980 amendments to RCRA exempted E&P wastes from Subtitle C hazardous waste requirements (Table 1). Instead they were placed under Subtitle D for nonhazardous substances. According to one scenario prepared by the API, drastic decimation of the U.S. oil and gas industry will take place if E&P wastes are placed under Subtitle C (Table 2).

Hardest hit will be the smaller independents whose existence primarily depends on operating marginal producing properties. Many major oil companies have already sold or are in the process of divesting themselves of low-volume producing properties.

Shutting in these producing properties runs counter to the U.S. Department of Energy's (DOE) program to prevent abandonment of wells prior to recovering, from known fields, additional remaining oil-in-place. Billions of barrels of oil could be left behind if the well abandonment proceeds before alternative technologies such as secondary and tertiary recovery processes are initiated.

As now written, the Senate bill excludes E&P wastes from the hazardous waste classification, but pressure from environmentalists may force changes (OGJ, Sept. 16, pp. 41-42). Some feel that RCRA will be reauthorized prior to next years presidential elections.

If E&P wastes are removed from Subtitle D, API's preference is that these wastes be under a separate RCRA subtitle that recognizes the substantial difference between E&P wastes and the hazardous wastes now classified under Subtitle C. By lumping E&P wastes into Subtitle C, the same disposal methods for all wastes have to be used. Already the hazardous waste industry finds opening new disposal sites difficult.

Areas differ widely as to the infrastructure that exists to dispose of wastes. For example, the Permian basin has a very developed infrastructure, but some companies are finding it necessary to ship their hazardous wastes as far as Corpus Christi, Tex., to find an approved disposal site.

Most companies are reluctant to state where specific wastes are disposed of. But this information is available from public records filed with the appropriate state or federal agency.

In industry's favor to maintain the hazardous waste exemption is the 1988 Environmental Protection Agency (EPA) conclusion that existing state and federal regulatory programs are generally adequate for controlling wastes from oil and gas operations.

EPA said that regulatory gaps can be filled by working with the existing state and federal regulations.

One industry group that works to fill these gaps in state programs is the IOCC. Three main areas of their involvement are:

• Identify where any gaps may exist in state programs and recommend specific upgrades to conform to the model guidelines.

• Develop training programs for state regulatory staff.

• Evaluate a comprehensive data management system for all state regulations.

WATER DISCHARGE

The preferred method for handling wastes is source reduction, followed by recycling, treatment, and proper disposal. By far the largest E&P waste stream (98%)2 is produced water. Depending on the clarity of the effluent, handling this stream can become complicated.

A lot of produced water is reinjected back into the formation for reservoir pressure maintenance, pumped down disposal wells into other formations, evaporated or percolated in pits, or released into surface waters in quantities that are permitted.

The Safe Drinking Water Act (SDWA) of 1974 and the Underground Injection Control (UIC) program established Class 2 wells for injection of oil field-related fluids. Minimum requirements for Class 2 wells are:1 2

• Only approved E&P wastes may be injected.

• No well may endanger an underground source of drinking water.

• Unless permitted by rule, all wells must be permitted before construction.

• All wells must periodically demonstrate mechanical integrity.

Discharge of produced water is governed by the National Pollutant Discharge Elimination System (Npdes) administered by the EPA under the Clean Water Act. Effluent guidelines prevent discharge to surface waters except in the following categories:1 2

• Discharge to coastal areas containing brackish waters not suitable for human use. This is primarily occurring in California, Louisiana, and Texas. Louisiana, in recent legislation, will virtually ban all discharges over the next 4 years.

• Discharges of low salinity produced waters that are of beneficial use in and regions west of the 98th meridian. Wyoming and California are the main states where this type of discharge occurs.

• Discharges from stripper wells. This is only allowed in some Appalachian states.

Although on some oil producing properties water production can be reduced, for most E&P operations water is necessary for improving ultimate recovery through secondary and tertiary processes. As fields age, more water is generally produced.

Substantial water can also be produced with gas. Coal bed methane wells have to be dewatered before gas production begins. Attempts to improve recovery from water-drive gas reservoirs frequently involve producing large quantities of water. Some of the methods that can be used to reduce the volume of produced water are:3

• In situ with a tail pipe water sink, alteration of relative permeability, and gel plugging.

• Source separation with passive and rotating hydrocyclones, cross-flow filtration, disc-centrifuging, and electrolytic treatment.

• Recycling through subsurface injection.

WASTE REDUCTION

Most companies now insist that service or contract companies bringing products onto a lease be responsible for removing any remaining product or chemical after the job.

Leaving items on a lease, even partly used paint cans, is now a rare event.

Some liquids from lease operations are also disposed of by mixing them into the product stream for sale.

Redesigned equipment is now appearing on leases. Fig. 1 illustrates how separator design is changing. Because on the new separator the float is on the outside, the separator does not have to be opened for repairing or cleaning of the floats.

Newer stuffing box designs on sucker-rod pumped wells prevent and contain leaks. Frequently, supervisory control and data acquisition systems (scada) monitor stuffing boxes and other lease equipment. The monitors alert operators of equipment failure that might produce wastes that have to be cleaned up or disposed of.

Many operators eliminate the need to dispose of steel drums by buying chemicals and lubricants in reusable plastic drums.

To prevent possible future problems, many companies are taking a proactive stance on the environment and often exceed current regulatory requirements.

Pits, even if allowed by regulations, are fast disappearing from many areas. Tanks are being substituted even for blow-down pits.

Existing pits are kept as small as possible and many times are lined even if not required by regulations.

The subject of controlling wastes on producing properties is becoming a new engineering discipline. Wojtanowicz3 calls this new area in petroleum engineering "environmental control technology" (ECT). By his definition, waste management deals with remediation whereas ECT aims at preventing wastes.

Wojtanowicz says that the dynamic nature of such regulations as Npdes permitting is forcing technology changes. The concepts of best practicable technology (BPT), the best controllable technology (BCT), the best available technology (BAT), and the new source performance standards (NSPS) imply that as oil field processes allow for cleaner effluent, the cleaner the effluent will have to become.

To better prepare their graduates for the reality that environmental considerations are influencing designs and economics, some petroleum engineering schools are including environmental courses in degree requirements. Even in their regular engineering program, schools now put more emphasis on teaching about environmental consequences.

Record keeping is one of the keys for knowing what wastes are being generated and where the waste is going. Of course, keeping records is costly. For some companies this cost is high enough to justify replacing a waste stream.

TREATING WASTES

Taking care of the waste on site is usually the least expensive alternative. Bioremediation to clean soils contaminated by hydrocarbons is showing promise in several areas. A recent paper 4 indicated successful bioremediation even within the Arctic Circle.

In that Exxon test, two 100,000-gal batches of microbes and nutrient-enriched formulations were applied to the surface of a gravel pad during the summer of 1990. The study revealed that nutrients alone might be sufficient to stimulate the growth of microbes that are capable of metabolizing petroleum hydrocarbons.

In some states spreading tank bottoms on roads is still permitted. But where this is not allowed, some companies have gone to recirculating through sumps to prevent heavy tank bottoms.

Saltwater contamination of surface land is a constant problem in waterflood areas. These leaks are commonly localized and are of insufficient volume to contaminate the groundwater.

In areas with freshwater wells that have been left without being plugged, some operators are going ahead and abandoning these wells even though a farmer may have drilled them. Their reasoning is to prevent being blamed for accidental contamination of groundwater from leaks or even natural processes such as animals falling into the well. Freshwater injection is safer than salt water, but in most of the country freshwater sources are being severely restricted, and most waterfloods now have to use saline water.

Naturally occurring radioactivity (NORM) is contaminating tubulars in a few producing areas. The contaminated tubulars are a potential hazardous waste although disposal regulations still have not been formulated. Many companies are either storing these tubulars until the regulations are clarified or running the strings back into the well and cementing them in place.

AIRBORNE WASTES

Dealing with waste gas streams in the atmosphere is complicated. Frequently, discharges are irregular. In these cases monitors might sound, but by the time the area is inspected the gas might have dissipated.

In the case of H2S, most of the is around lease batteries. For some personnel safety, state regulations are starting to require either two gaugers or automatic tank gauging on properties that produce sour crudes.

To improve on one-point detectors, testing is being done with lasers that can scan a lease and pinpoint the H2S or other gas clouds as they move.

In California, air quality is an important environmental issue. Several areas such as the San Joaquin Valley air basin portion of Kern County are classified as nonattainment areas under the National Ambient Air Quality Standards (Naaqs) and the California Ambient Air Standards (Caaws) for two criteria pollutants: ozone and suspended particulate matter with an aerodynamic diameter of 10 m or less (PM10).

Chappelle, et al.,5 describe the complexity of operations at the Elk Hills field under these restrictions.

Air emission sources at Elk Hills include:

• Reactive organic gases (ROG)

• Oxides of nitrogen (NOx)

• Carbon monoxide (CO)

• Sulfur dioxide (SO2)

• Sulfates (SO4)

• Total suspended particulate matter

• Particulate matter equal to or smaller than 10 m in aerodynamic diameter (PM10)

• Hydrogen sulfide (H2S)

• Lead (Pb)

• Benzene (C6H6).

Most air regulations are enforced by the San Joaquin Valley Unified Air Pollution Control District (APCD) under authority from the EPA through the California Air Resources Board.

The principal air regulations include New Source Review (NSR), New Source Performance Standards (NSPS), National Emissions Standards for Hazardous Air Pollution (Neshaps), California air toxics regulations, transportation control measures, and PM10 planning.

In Elk Hills, all equipment that is over 50 hp is reviewed by the APCD. After issuing permits, specific emission-sampling limits are assigned to the equipment for all criteria pollutants. Any increase or decrease in emissions must be authorized by an Authority to Construct (ATC) from the APCD.

Elk Hills currently holds over 650 permits issued by the APCD. In early 1991, the field also had approximately 50 ATCs for new or modified equipment. In addition to these APC-granted ills has a Prevention of Significant Deterioration (PSD) from EPA which addresses emission from 34 compressor engines.

California and federal clean air acts require new sources of emissions in nonattainment areas to provide:

• The best available control technology (BACT) for increases of nonattainment pollutants.

• Full offsets for all emission increases.

• BACT for all emissions increases over specified limits.

Reductions made in excess of those mandated by law or regulation may be banked for future use.

REFERENCES

1. API Environmental Guidance Document, Jan. 15, 1989.

2. Interstate Oil Compact Commission, EPA/IOCC Study of State Regulation of Oil and Gas Exploration and Production Waste, December 1990.

3. Wojtanowicz, A.K., "Oilfield Environmental Control Technology: A Synopsis," Paper No. 22815, SPE Annual Conference and Exhibit, Dallas, Oct. 6-9, 1991.

4. Liddell, B.V., Smallbeck, D.R., and Ramert, P.C., "Arctic Bioremediation: A Case Study," Paper No. 22155, SPE Annual Conference and Exhibit, Dallas, Oct. 6-9, 1991.

5. Chappelle, H.H., Donahoe, R.L., Kato, T.T., and Ordway, H.E., "Environmental Protection and Regulatory compliance at the Elk Hills Field," Paper No. 22815, SPE Annual Conference and Exhibit, Dallas, Oct. 6-9, 1991.

Copyright 1991 Oil & Gas Journal. All Rights Reserved.