Table of Contents

Vol. 6, No. 4
4th Quarter 2000

Managing Produced Water
by Karl Lang, Hart Energy Publications

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 the alternatives have included new technologies for handling produced water and for reducing the amount produced through downhole separation. This article looks at the current state of dowhhole separation in particular.

In 1995, US domestic hydrocarbon production totaled 2.4 billion barrels of oil and 19.5 Tcf of gas. But in order to reach that total it was necessary to simultaneously produce nearly 18 billion barrels of water (Petrusak, 2000). More than 92% of this water is re-injected, with 71% used for EOR and 21% disposed of in Class II injection wells. Only about 3% of produced water was discharged to the surface under NPDES permits in 1995, 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 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/Bbl, the fully burdened cost of water disposal, including capital and operating expenses, has been estimated at between $1.30/Bbl and $2.00 per barrel, depending on volume (GTI, 1999). The added costs of permitting and legal liability boost the total industry burden to the tens of billions.

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 water hauling costs from, say, the chemical costs or the permitting costs. 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."

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
2. Conventional disposal methods
3. Downhole oil/water or gas/water separation and disposal methods

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). 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 water to the surface and reinject.
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.

Case Studies

Two studies published in 1999 looked at the performance of DOWS and DGWS installations independently. 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, the overall performance of this technology should improve.

Table 1: Results of Downhole Separation and Disposal Studies

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 bpd. The system separates oil from water and then uses a pump to inject the water to disposal and lift the oil to surface.

Gravity separation systems are manufactured by a number of rod pump suppliers. 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 developed by Texaco and others, 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.

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

DGWS System Design Options

DGWS systems utilize rod pumps, electric submersible pumps (ESPs) and progressive cavity pumps (PCPs). These all operate on the fundamental fact that gravity separation of gas and water efficiently 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. The pumping action loads the tubing with water from the casing tubing annulus. When 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.

A second type of rod pump-operated DOWS system is termed the modified plunger pump. 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 low 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.

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 flow rates and are generally more economic in deeper wells. Another alternative is a rod string-powered PCP.

An economic comparison of various DGWS technologies with conventional water separation facilities conducted 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 8,000 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.

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

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, the 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 $3,000 and a modified plunger rod pump about $4,400, excluding installation.

Current Activity Related to DOWS

A number of new DOWS installations have been carried out since the Argonne/DOE study. One new DOWS installation has been done by Marathon in Wyoming, Phillips Petroleum has completed the first offshore installation in the China Sea, and two new installations have been done 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. "This was only 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 eight-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. 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.

To read the complete article, including full reference citations, figures and additional details, visit www.pttc.org.

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 in the negotiation stage.

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 test 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. 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