Producers In The "Water Business"

Water Management Options

Downhole Separation and Disposal

Case Studies

Table 1

DOWS System Design Options

Figure 1

Table 2

Figure 2

DGWS System Design Options

Figure 3

Figure 4

Costs

Current Activity Related to DOWS

Regulatory Issues

Downhole Separation to Play Increasing Role

References

Sidebar 1
Joint Venture Provides Innovative Produced Water Management

Sidebar Figure

Sidebar 2
Water Recycling and Modified Reverse Osmosis

Sidebar3
High-Water Saturation Dewatering Projects

Managing Produced Water
by Karl Lang, Hart Energy Publications
Excerpts in PTTC Network News, 4th Quarter 2000

In the mature producing basins of the U.S., managing water production is an important part of the oil and gas business. In the words of one producer, “When you realize you’re spending several thousand dollars a week on water, you start thinking carefully about alternatives.” Some of these alternatives have included new technologies for handling produced water or for reducing the amount produced. As with any new technology, the challenge for the smaller producer is to take advantage of cost-saving benefits as early as possible, without becoming a major contributor to the learning curve investment. This is particularly true in the case of water management, because one of the most promising new technologies, downhole separation, can require a significant capital investment on the strength of what to date has been mixed performance results. This article looks at the current state of a number of new technologies for produced water management, and focuses on downhole separation in particular.

Producers In The “Water Business”

In 1995, US domestic hydrocarbon production totaled 2.4 billion barrels of oil and 19.5 Tcf of gas. In order to reach that total however, it was necessary to simultaneously produce nearly 18 billion barrels of water (Petrusak, 2000). That’s enough water to cover the state of Wyoming with a little less than ½ an inch (or, if you prefer, Washington DC to a depth of 53 feet). More than 92% of this water was re-injected, with 71% used for EOR and 21% disposed of in Class II injection wells. Only about 3% of the water volume produced in 1995 was discharged to the surface under NPDES permits, and almost all of that was related to coalbed methane production. Another 2% was put to beneficial use (irrigation, livestock, etc.). Although the number of producing oil wells has declined over the past five years, the general trend of increasing water production with increasing field maturity practically guarantees that total annual water production is comparably high today.

The cost of lifting, separating, handling and disposing of this water is substantial. While U.S. water hauling costs generally average about $1/barrel, the fully burdened cost of water disposal, including capital and operating expenses, has been estimated at between $1.30 and $2.00/barrel, depending on volume (GTI, 1999). Adding in permitting and other legal costs boosts the total industry burden to the tens of billions. This burden is disproportionately borne by the independent producer, who is more likely to be the operator of older, higher water cut wells.

Approaches to this problem vary. “Some companies are very reactive, some are more proactive and some see the problem as an opportunity,” says Jon Rudolph, Manager of Produced Water Management for Gas Technology Institute’s E&P Services. GTI interviewed 35 operators in Texas, Louisiana and Colorado to learn how they managed produced water and came up with some interesting insights. “Many companies don’t recognize or account for the full cost of water management,” says Rudolph. “Companies are organized functionally in ways that tend to compartmentalize the permitting costs from, say, the chemical costs or the hauling costs. Water’s role and impact can be significantly underestimated. If you look at water management in a holistic way and recognize it’s importance from the initial estimate of a prospect’s recoverable reserves right through to the valuation of an asset for divestiture, you can make decisions that will improve your overall economics.”

This approach can result in something as simple as recognizing the need to drill a well a hundred feet deeper to allow for future injection into a water zone via a downhole separation and disposal system. “A truly integrated approach to water management matches the best technology value to life-cycle needs,” adds Rudolph. “Some independent operators see this as their strength. They are water management experts and sell that expertise to larger companies that are focused more on exploration than reducing the costs of production.”

Water Management Options

The primary technologies available for dealing with produced water generally fall into one of three categories, any combination of which may be employed in a given field:

1.      Conformance control measures. These are modifications to well completions or production patterns designed to reduce the volume of water produced from the formation.

2.      Conventional disposal methods. Surface handling and disposal of separated, produced water, either into injectors for enhanced recovery, into disposal wells, through surface discharge, or through beneficial uses (e.g., irrigation).  

3.      Downhole oil/water or gas/water separation and disposal methods. Subsurface equipment that separates the hydrocarbon and water phases, disposes of the water into a non-productive zone, and produces the relatively water-free hydrocarbon to the surface.

Most operators rely on a combination of technologies from categories one and two. A number of new options have been proposed for reducing the costs or increasing the efficiency of surface water treatment and disposal processes (e.g., see sidebar on Crystal Solutions, LLC). Some researchers are looking at ways to utilize produced water as a replacement for fresh water in remote, dry areas (e.g., see sidebar on recycling modules and modified reverse osmosis). For the most part, operators continue to rely on conventional disposal solutions and focus on finding ways to reduce the cost of those operations as much as possible. However, over the past several years the third category, downhole separation and disposal, has seen an increased number of installations and attention.

Downhole Separation and Disposal

Downhole oil/water separators (DOWS) and downhole gas/water separators (DGWS) are devices that separate hydrocarbons from water at the bottom of a well. A significant portion of the separated water is reinjected into a non-productive interval, while the oil, gas and remaining water are produced to the surface.

Reducing the volume of water that must be produced, handled at the surface, and reinjected, has a number of benefits: 

1.      Reduced facility investment costs – If water volumes do not increase over the life of the field, facility and piping expansions to avoid constraining oil production will not be necessary. Expensive disposal systems will not be needed.

2.      Reduced chemical costs – Increased water production results in increased treating chemical consumption (scale inhibitors, corrosion inhibitors, emulsion breakers, etc.).

3.      Reduced power consumption – Depending on the type of lifting system in place in a field and the type of DOWS or DGWS selected, the power requirement to separate and reinject downhole can be significantly less than that required to lift the fluids to the surface and reinject the water.

4.      Increased oil or gas production – This can result if surface facilities are constrained by water volume and wells are not producing at their optimum drawdown, or if producible wells are lost to water injection. Also, by reducing the operating costs, the economic limit of a field can be extended, increasing the ultimate recovery.

5.      Reduced environmental risk – Reduced risk of surface spills and reduced risks of potable water formation contamination during reinjection.

 Offsetting these benefits are two important issues: the equipment is expensive to purchase and install, and its performance appears to be dependent on a number of key well and fluid characteristics. In other words, downhole separation and disposal may not be cost-effective for all high-water cut wells.

Case Studies

Two independent studies published in 1999 looked at the performance of DOWS and DGWS installations. The first, undertaken by Argonne National Laboratory, CH2M-Hill and the Nebraska Oil & Gas Commission and funded by the U.S. Department of Energy, looked at data from 37 DOWS installations by 17 operators in the U.S. and Canada (Veil, 1999). The second, undertaken by Radian International for Gas Research Institute (now Gas Technology Institute), looked at 53 DGWS installations by 34 operators in the U.S. and Canada (GTI, 1999). The results of these two analyses revealed that performance has been mixed (Table 1). Depending on the definition of “success,” somewhere between 45% and 65% of the installations could be considered successful. However, as operators and equipment vendors gain experience in selecting candidate wells and as equipment design improvements are made, indications were that the overall performance of this technology should improve.

Table 1: Results of Downhole Separation and Disposal Studies

	DOWS (Argonne/DOE)	DGWS (Radian/GTI)
Cases Reviewed	37	53
Operators Involved	17	34
Location	10 US 27 Canada	35 US 18 Canada
Type of Installation	21 Hydrocyclone 16 Gravity	32 Modified Plunger 17 Bypass Toll   4 ESP
Performance	19 Oil increase 12 Oil decrease   6 No change or undefined 27 Decrease in water to surface	29 Gas increase 13 Gas decrease 11 No change or undefined
Reasons for Failure	· Low injectivity in disposal zone · Insufficient zone isolation (recycling) · Plugging due to sand or fines · Corrosion or scaling	· Low injectivity in disposal zone · Insufficient zone isolation (recycling) · Poor wellbore integrity (includes sand production)

 

DOWS System Design Options

Two basic types of DOWS systems have been developed: hydrocyclone separation powered by a downhole electric motor or a rod pump, and gravity separation with production via rod pump (Veil, et al., 1999). The hydrocyclone DOWS systems can handle up to ten times the volume of water that can be produced with gravity systems, which have a limit of about 1000 barrels per day (bpd). A hydrocyclone system (Figure 1), separates oil from water and then uses a pump to inject the water to disposal and lift the oil to surface. One system offered by Centrilift has two modes of operation: the “pump through” system where reservoir fluids are pumped into the separator, and the “pull through” system where the reservoir provides the pressure to enable flow through the separator and the separated fluid volumes are pumped in their respective directions. With the push through system, the flow to surface can be more readily controlled. Production fluid homogeneity is maximized and free gas is dispersed, compressed and put back into solution. With pull through systems, emulsions are minimized since there is less shearing of the produced fluid.

Figure 1: DOWS Hydrocyclone System

Gravity separation systems are manufactured by a number of rod pump suppliers (Table 2). Separation of oil and water takes place in the annulus and water is removed from a point below the oil/water contact. A dual action pumping system (DAPS) employs a rod pump with two pump assemblies and an injection valve. On the upstroke, water is pulled into the tubing through the lower inlet valve and oil/water is lifted up the tubing via the upper pump assembly. On the downstroke, oil/water is pulled into the upper pump assembly while water is pumped into the injection zone. A new modification of this system (Figure 2), the triple-action pumping system (TAPS), adds an additional pump assembly with a smaller plunger (Wacker, et al, 1999). TAPS permits injection at higher pressure and is a relatively simple and inexpensive system that relies on only one specialty piece of equipment.

Table 2: DOWS and DGWS Vendor Information

Figure 2: DOWS Triple-Action Pumping System (after Wacker, et al., 1999)

The study carried out for DOE (Veil, et al., 1999) determined that DOWS systems have a higher chance of success if they are installed in wells with:

·        High water oil ratio and relatively high gravity oil

·        A chemically compatible injection zone isolated from the producing zone

·        Good mechanical integrity

All of the installations where pre- and post-installation water production data were available, showed a decrease in the volume of water brought to the surface. In 22 of 29 trials the reduction exceeded 75%. The top three gravity separator installations exhibited increases of between 100% and 235% in oil production. The top three performing hydrocyclones exhibited increases between 450% and 1160% in oil production (Veil, et al., 1999).

DGWS System Design Options

DGWS systems utilize rod pumps, electric submersible pumps (ESPs) and progressive cavity pumps (PCPs). All operate on the fundamental fact that gravity separation of gas and water occurs in the annulus as formation fluids enter the wellbore. The simplest DGWS device is a bypass tool in which the bottom end of an insert sucker rod pump is seated (Figure 3). The pumping action acts to load the tubing with water from the casing tubing annulus. When the the hydrostatic head in the tubing is great enough, the water drains into the disposal zone below the producing perforations and packer. Gas flows up the tubing-casing annulus.

Figure 3: DGWS Bypass Tool (courtesy of Gas Technology Institute)

 A second type of rod pump operated DOWS system is termed the modified plunger pump (Figure 4). This system consists of a short section of pipe with one to five ball-and-seat intake valves and an optional back-pressure valve, run below a tubing pump in which the traveling valve has been removed from the plunger. On the upstroke the solid plunger creates a lower pressure area in the barrel, allowing the ball-and-seat valves to open and water to enter.  On the downstroke, the plunger moves the fluid down and out of the barrel and into a disposal zone below the packer.

Figure 4: DGWS Modified Plunger Tool (courtesy Gas Technology Institute)

Electric submersible pumps are another alternative, and in the case of DGWS they would be configured as a bottom-discharge system with the pump below the motor rather than in the conventional motor-on-bottom design. ESPs provide for very high disposal rates and are generally more economic in deeper wells. Another alternative is a rod string powered progressive cavity pump.

An economic comparison of various DGWS technologies with conventional water separation facilities carried out by GTI, showed that the selection of an appropriate DGWS tool is primarily a function of water flow rate and well depth (GTI, 1999). For water production rates less than 50 bpd, conventional surface disposal is most cost effective. Bypass tool systems are more cost effective in the 25-250 bpd range, up to a maximum depth of about 8000 feet. A modified plunger system was shown to be most cost effective for 250-800 bpd over about the same depth range. For high water rates (>800 bpd) and at depths below 6,000 feet, ESP systems are typically more cost effective. Of course, these rules-of-thumb must be considered approximate.

The GTI study also determined that a DGWS system stands the best chance of success when it is installed in a well with:

·        Well cemented casing

·        Minimal sand production

·        Soft water (little scaling)

·        Water production of at least 25-50 bpd

·        Disposal costs greater than $25-$50/day

·        A low pressure, high injectivity disposal zone below the producing interval

While these criteria are somewhat restrictive, quite a few gas wells could be considered viable candidates, particularly if the potential for an eventual DGWS installation is considered prior to completion. (Note: The GTI report (GRI-99/0218), which is available on CD and includes an interactive economic model to facilitate evaluation of candidate wells, is available from GTI at www.gastechnology.org/).

Costs

A hydrocyclone DOWS system can cost between $90,000 and $250,000, excluding the cost of a workover to install the equipment, which can add another $100,000 or more. Hydrocyclone DOWS systems are from two to three times the cost of a comparable conventional ESP. Gravity separation DOWS systems are considerably less expensive, and range between $15,000 and $25,000, plus the cost of an installation workover. (Veil, et al.,1999). Obviously, any work required to prepare an appropriate disposal zone can add significantly to the cost.

The cost of a DGWS system can be less, depending on the system. For example, a bypass tool runs about $1,200 to $3000 and a modified plunger rod pump about $4,400, excluding installation. An ESP for a DGWS system runs between $10,000 and $30,000, excluding additional equipment and installation (GTI, 1999). These numbers are rough approximations based on typical operating specifications, but they give some idea of the relative costs of these technologies.

Current Activity Related to DOWS

A number of new DOWS installations have been carried out since the Argonne/DOE study was completed. One new DOWS system has been installed by Marathon in Wyoming, Phillips Petroleum has completed the first offshore installation in the China Sea, and two new installations have been completed by Astra in Argentina, according to Bruce Langhus, one of the authors of the DOE report. “The US DOE feasibility project is continuing with three new field trials operated by Texaco, UNOCAL, and Avalon Exploration. The Texaco and UNOCAL wells have ceased operations while the DOWS equipment in the Avalon well is expected to be installed during the first quarter of 2001.”

The Texaco well employed the first TAPS system (Wacker, et al, 1999), a beam-pump powered gravity separation system designed to operate at high injection pressures. The UNOCAL well project, the first hydrocyclone equipped DOWS installation in the East Texas area, has finished the data-gathering phase and the well has had its DOWS equipment removed. “As has been the case with many DOWS installations, the technical and economic success of this installation was mixed,” said Langhus. A report on the results of that work is expected to be completed next year.

The Avalon well, located just north of Oklahoma City, is expected to be the first DOWS test in an oil field dewatering project. Recently, some operators have found that under certain circumstances it can be profitable to pump large volumes of water from watered out wells, if the reservoir’s dual porosity system allows unrecovered oil to drain into a fracture system that is drawn down by the removal of water (see sidebar). “This has only been feasible in fields with an existing water disposal infrastructure,” adds Langhus. “The possibility of economically dewatering wells in fields without that infrastructure, using an electrical submersible pump DOWS system, is what this test is designed to investigate.”

Langhus conducted the first PTTC-sponsored DOWS workshop held in Lansing, Michigan in July, 2000. More of these 8-hour workshops are planned as industry interest picks up. 

Regulatory Issues

Prior to January 2000 the state regulatory community had not yet come to a general agreement on how to classify DOWS and DGWS installations that simultaneously inject and produce. Some states had chosen to classify DGWS wells as Class II injection wells or regulate them as such (Texas, California, Colorado, Oklahoma). Four states had chosen to regulate DOWS wells with requirements similar to regular Class II injection wells (Texas, Oklahoma, Louisiana, and Colorado). Other states had not yet decided how to deal with the problem.

Responding to requests from UIC offices in several regions, the U.S. Environmental Protection Agency issued guidance on the issue of wells with downhole separators on January 5, 2000. The EPA classified them as Class II enhanced recovery wells. This determination was based on the fact that fluid was injected and production of hydrocarbons was enhanced. Both DGWS and DOWS installations were included in this definition. Under the UIC program, a permit must be obtained from the appropriate state or federal agency prior to installation of equipment that would cause a well to be classified as a Class II enhanced recovery well. In most cases the states have primacy in establishing standards.

Downhole Separation To Play Increasing Role

The convergence of two trends will most likely ensure that downhole separation and disposal technology sees wider application in the future: (1) increasing water cuts in older fields and (2) greater economic risks associated with environmental damage. It will be important, however, to select wells that stand the best chance of benefiting from downhole separation and disposal technologies.

References

Petrusak, R.L.; Freeman, B.D.; Smith, G.E.; 2000. “Baseline Characterization of U.S. Exploration and Production Wastes and Waste Management,” SPE paper 63097 presented at the SPE Annual Technical Conference and Exhibition, Dallas, TX, October 1-4, 2000.

Gas Technology Information; 1999. “Technology Assessment and Economic Evaluation of Downhole Gas/Water Separation and Disposal Tools,” GRI-99/0218, report prepared for Gas Research Institute by Radian International, November 1999.

Veil, J.A., Langhus, B.G., and Belieu, S.; 1999. “Feasibility Evaluation of Downhole Oil/Water Separation (DOWS) Technology,” prepared for U.S. Dept. of Energy, Office of Fossil Energy, NPTO, by Argonne National Lab, CH2M-Hill, and Nebraska Oil & Gas Conservation Commission, January 1999. (Available online at http://www.ead.anl.gov/pub/dsp_detail.cfm?PubID=31

Wacker, H.J.; R.M.Parker; L. Stuebinger, R. Harding; and B. Watson; 1999.
"Test Proves Out Triple-Action Pump in Downhole Separation", Oil & Gas
Journal, Oct. 4, 1999., pp. 49 - 55.

Doran, G.F.; Williams, K.L.; Drago, J.A.; Huang, S.S.; and Leong, Y.C.; 1999. “Pilot Study to Convert Field Produced Water to Drinking Water or Reuse Quality,” SPE paper 54110 presented at 1999 SPE International Thermal Operations and Heavy Oil Symposium, Bakersfield, CA, March 17-19, 1999.

Sidebar 1
Joint Venture Provides Innovative Produced Water Management

After nearly one year of operation, Crystal Solutions, LLC, a joint venture of Gas Technology Institute (formerly Gas Research Institute) and BC Technologies, has plans to expand its operations in response to a high level of customer interest in the Rocky Mountain region. The company began accepting water at its first major commercial treatment facility near Wamsutter, Wyoming late last year. Freeze-Thaw/Evaporation. FTE®, the company’s innovative treatment process, is a simple and economic solution to year-round treatment of produced water in regions that experience seasonal sub-freezing temperatures. The FTE process relies on naturally occurring temperature swings to alternately freeze and thaw produced water, concentrating the dissolved solids and creating relatively large volumes of clean water suitable for various beneficial uses.

The Wamsutter facility, which began operating in December 1999, serves the Red Desert/Great Divide Basin of Wyoming. Nine independent producers have contracted with Crystal Solutions to handle their produced water, and the facility is operating near design capacity. The joint venture also entered into a contract to operate a McMurry Oil Company-owned facility (now owned by AEC Oil & Gas USA Inc. following its acquisition of McMurry Oil). "It's been an exciting first year,” says John Harju, GTI Project Manager and Vice President of Crystal Solutions, LLC. “We hope to continue to expand the operating sphere of Crystal Solutions, ideally getting two or more new facilities designed and permitted within the next year and potentially expanding the capacity of the current facility.” Three potential new facilities in Wyoming, one in Utah, and two more in Colorado are currently at the negotiation stage.

Early evaluations of the process performed in conjunction with Amoco Production Company (now BP Amoco) in the San Juan Basin in New Mexico, and a commercial deployment evaluation with McMurry Oil Company in the Green River Basin in Wyoming, demonstrated significant economic and environmental benefits from the process. These pilot projects, conducted by BC Technologies, the University of North Dakota's Energy & Environmental Research Center, GTI and the Department of Energy (DOE), showed that concentrating produced brine through FTE cut overall disposal and/or treatment costs significantly. Such cost savings can help increase production from marginally economic wells or spur development of new gas resources.

 
The principle behind freeze-thaw is based on the fact that salts dissolved in water lower the freezing point of the solution below 32 degrees F.  Partial freezing occurs when the solution is cooled below 32 degrees F, but held above the depressed freezing point of the solution. In that range, relatively pure ice crystals form, and an unfrozen brine solution containing elevated concentrations of the dissolved salts can be drained away from the ice. When the ice melts, it is essentially pure water. For example, during the 1999-2000 cycle, field data show that a feed water with 14,000 mg/l of total dissolved solids (TDS) is converted to a brine with 64,300 mg/l TDS and a melt water with only 924 mg/l TDS. Roughly 55% of the feed is converted to melt water, about 30% is lost to evaporation and/or sublimation, and only about 15% of the original feed remains as concentrated brine – which in this particular case, due to the brine having a potassium chloride concentration in excess of 2%, results in a usable product for drilling applications.   

 
The produced water is frozen by spraying onto a lined pond (freezing pad) when winter temperatures reach the appropriate level (see figure). The concentrated brine is drained from the pad during the freezing cycle, and the purified melt water is collected during the thaw cycle.

 
To learn more about this and other technologies being commercialized by GTI and its partners, contact John Harju at jharju@gastechnology.org/ or John Boysen at john_boysen@hotmail.com/.  

FTE Water Treatment  Facility

Sidebar 2
Water Recycling  and Modified Reverse Osmosis

The Texas Water Resources Institute (TWRI) is funding a Global Petroleum Research Institute (GPRI) effort to develop projects directed at the management of produced water. The first project will be to develop small, modular units that can be used to produce fresh water from produced water streams at lease sites. David Burnett, GPRI Director of Technology, explains that this project is not necessarily trying to provide a new produced water treatment solution, but to find a way to use produced water to help solve other problems. “There are a number of situations where relatively small volumes of fresh water are needed at remote sites. Restoration of overgrazed ranchland is one example. Just one or two thousand gallons a day from a produced water facility, perhaps just 10% of the total volume, could be used to restore a two-acre plot of range land in one-half to one-quarter the time it would take without water,” says Burnett. Portable, remotely operated water treatment modules utilizing membrane technology might be a way to provide on-site water treatment in an economic fashion. Marathon Oil Company at the Yates Field in West Texas has joined the project and will offer an area to be used for wildlife habitat restoration. One benefit of the program will be to increase the availability of water resources in regions where their absence currently limits economic stability and diversity. Ultimately, the technology developed could reduce the cost of wastewater disposal. Persons interested in participating in this program may contact David Burnett at burnett@gpri.org.

Another project being undertaken by the Petroleum Recovery Research Center (PRRC), a research division of the New Mexico Institute of Mining and Technology, relates to the use of a modified reverse osmosis (RO) technology for producing fresh water from a stream of produced brine. Earlier studies have shown that, while expensive, RO might be an option for turning produced water into a drinking water resource under certain circumstances (Doran, et al., 1999). This work, just recently begun in September 2000, will be funded in part by DOE’s National Petroleum Technology office in Tulsa, Oklahoma. The technology will employ natural clays to separate produced water into a fresh water stream and a concentrated brine or solid salt for disposal. The goal will be to develop a technology that is more economical and operates at lower pressures than conventional reverse osmosis desalination equipment.

Sidebar 3
High-Water Saturation Dewatering Projects

A report in Petroleum Technology Digest in September 2000, described how New Dominion, LLC of Tulsa, Oklahoma had used electric submersible pumps to produce 50,000 bwpd from 28 wells in a 4800-acre Hunton limestone field in Oklahoma. This drawdown resulted in a field-wide oil and gas production rates that climbed from essentially zero to about 2000 bopd and 14 MMcfd respectively. Recoverable reserves of 2.2 million barrels and 16.2 Bcf of high-Btu gas have been developed in what was considered to be a “watered-out” field. This required an infrastructure investment of $4 million, not including well costs. About 60% of per well average monthly operating expense of $6,000 is required for electricity for the pumps.

According to David Chernicky of New Dominion LLC, "We looked carefully at downhole separation and found that the degree of separation possible with existing technology was just not sufficient for our purposes." The economics of oil reservoir dewatering relies on capturing essentially all of the relatively small amount of oil produced along with an enormous volume of water. "Getting close to 100% separation with downhole equipment wasn't possible," said Chernicky, "So we plan to continue to use surface separation in our new projects." New Dominion has plans to duplicate their success in another Oklahoma field where they have become a significant leaseholder, using the same approach.

Author: Karl R. Lang is a Director of Hart Publication's Hart/IRI Fuels Information Services, a part of Chemical Week Associates. He edits GasTIPS, a technical journal produced by Hart for Gas Technology Institute (GTI), and contributes to a number of Hart publications. E-mail: klang@phillips.com.