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Produced Water |
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Based on a workshop sponsored by PTTC's Southwest Region, held on Dec. 4-5, 2002 in Farmington, NM
To increase well/lease profitability, producers should implement a strategy to reduce excessive water production. Industry has developed proven practices for determining if there really is a problem, correctly diagnosing the problem and determining the appropriate solution. Solutions can range from the simple mechanical to chemical such as polymer gels. With proper application and operator/provider cooperation, success rates with polymer gels can exceed 90%. Industry increasingly is looking for ways to treat produced water for beneficial use, but much R&D remains to be done before the practice becomes profitable and widespread.
On average in the U.S., for every barrel of oil produced, there are some 8-9 barrels of water produced. This high volume of produced water significantly increases power consumption and operating costs and can cause environmental problems. Operators are constantly searching for improved technologies to manage the produced water issue, including even treating it for beneficial use.
Coalbed Methane, Desalination, Polymer Gel Treatments, Produced Water, Reverse Osmosis
DOE's Reservoir Efficiency Processes,
Jerry Casteel, US DOE National Petroleum Technology Office
A Pilot Operation to Desalinate Oilfield-Produced Brine, Discussion of Pretreatment Options and Lessons Learned,
Will Palmer, Read & Stevens Production
Modified Reverse Osmosis for Treatment of Produced Water
Mike Whitworth, Univ. of Missouri-Rolla
Produced Water Initiative
Dave Mankiewicz, BLM Farmington
Sandia National Laboratories, Albuquerque, NM
Petroleum Recovery Research Center, New Mexico Tech
Desalination
Desalination R&D at Sandia National Lab. Fresh water falls within Sandia's mandate to address critical societal infrastructure issues. Energy and water are intimately connected—thermoelectric power generation is responsible for 45% of all freshwater withdrawals and only agriculture exceeds the energy industry's water demand. Worldwide, some 12,500 desalination plants supply 5.5 billion gallons per day or 1% of the world's drinking water. Reverse osmosis and distillation are the most common systems. Even a $70 billion investment over the next 20 years would only increase capacity by some 10 billion gallons per day, which would still be very minor compared to overall demand. Desalination costs must be reduced by a factor of 3-10; so novel treatment ideas and concepts are required.
Inland desalination is of primary interest in the U.S. Under a Memorandum of Understanding (MOU) with the Bureau of Reclamation, Sandia is establishing the Tularosa (NM) Basin National Desalination Research Center. It will focus on application of renewable energy to desalination processes, evaluate technologies that address environmental issues of inland brine disposal and evaluate technologies for produced brine treatment. Produced water management is a major concern of the coalbed methane (CBM) industry. Treatment options depend on each basin's gas/produced water ratio. Rangeland or agricultural beneficial uses are the most common. Treatment typically requires more than total dissolved solids (TDS) removal, the removal of hydrocarbons being just one example. Sandia is evaluating treatment options (pretreatment, the processes themselves, and post-treatment). Options will be identified and assessed for each basin and treating guidelines including a simulation-based decision support tool developed. The guidelines should be completed in late 2003.
Pretreating and Desalinating Oilfield and CBM Brine. Producers in southeast New Mexico pay about 35 cents/barrel for disposal, and CBM water disposal costs can be much higher. In the southeast, producers dispose of some 1 million barrels per day of produced brine, while at the same time paying nearly the same rate to produce and use some 10,000 barrels per day of fresh ground water. These factors, along with the arid climate, provide a driving force for treating at least a portion of the produced water. Pretreatment, most notably for hydrocarbon and solids removal, is critical. The Petroleum Recovery Research Center (PRRC) at New Mexico Tech, is leading a project to optimize pretreatment processes. Factors which are being considered include: cost, hydrocarbon and solids removal, H2S stripping and disposal, scale inhibition, maintenance and operational factors, boron removal in some instances, disposal of byproducts (NORM), and field trial experience.
Pretreating processes include: (1) micro air filtration, oxidation, filtration (field trial in Lea County, removed organics and reduced TDS), (2) filter-based, pH adjustment, antiscalant added (field trial in California overcame numerous problems), (3) biological reactions, (4) absorbent polymeric material, and (5) macro porous polymer extraction (used offshore). There is a promising absorbent polymeric material that warrants consideration in that it provides 100% hydrocarbon recovery, generates no waste sludge, and can handle oil loading of several thousand ppms. In principle, biological reactions are simple and inexpensive. Biological treating is a two-step process involving treatment in an anaerobic reactor (80-90% biochemical oxygen demand (BOD) removal, 95-98% H2S removal) followed by aerobic polishing (> 98% BOD removal). Testing will involve bench-scale testing, a laboratory-scale pilot test, and a field-scale pilot study. Ultimate goal is to optimize the biological process and determine process economics.
Testing Clays for Reverse Osmosis Membranes. In their DOE-supported "Water Dog" project, PRRC and the University of Missouri-Rolla are evaluating clay membranes for use in reverse osmosis units. In addition to being lower cost than conventional membranes, clay membranes offer potential for treating higher salinity brines (conventional membranes limited to about 45,000 ppm TDS). Although thin clay membranes have been achieved in the lab, construction of spiral-wound clay membranes has not yet been accomplished. Early lab results indicate that membrane efficiency is not as high as hoped for in that NaCl precipitation rates are not adequate for practical separation. Additional work with electrically-enhanced clay membranes is in progress. Researchers are also exploring azeotrope-induced precipitation. When ethanol is added to water, it produces a single phase (azeotrope) that readily precipitates high concentrations of salt. The research challenge then becomes finding a practical way of separating the ethanol and water.
Field Pilot, Southeast New Mexico. A 10-25 gallon per minute pretreatment and reverse osmosis unit was operated for two months, treating oilfield brine of about 40,000 ppm TDS. Goal was to achieve about 6,000 ppm TDS for agricultural use. In this pilot unit, volatile organic carbons and H2S were not captured. Hydrocarbon content of the inlet brine ranged from 85 to 200 ppm. To work properly, modifications to the pretreatment scheme (additional chemical processing, aeration, and a settling tank) were required. With these modifications, suspended organics were reduced to around 5 ppm. The reverse osmosis unit was able to achieve lower TDS than anticipated, proving that a 40,000 to 6,000 reduction is easily achievable. Actual values were often less than 500 ppm. Pilot testing established that the process might be competitive with brine disposal costs and that not considering any value for beneficial use of the treated water.
Other Water Related Projects in New Mexico
Produced Water Mapping and Tools. In a DOE-supported PUMP (Preferred Upstream Management Practices) project, PRRC staff is developing a web-based, GIS-oriented water information system containing both groundwater and produced water data. Tools to be incorporated within the system include a fuzzy risk analysis tool and a corrosion and scale management toolkit. This toolkit will create a qualitative Corrosivity Index for various producing formations and regions, incorporate scale prediction tools, assemble an online reference book, and collect corrosion information and current management practices. The database now contains nearly 3,000 produced water samples, while there are about 30,000 samples in the groundwater database. Additional data contributions are welcomed.
Produced Water and Subsurface/Surface Water Interaction, New Mexico. In late 2002 PRRC researchers began a study evaluating interactions between produced water and subsurface/surface water in the Roswell and Pecos River basins. Data (water chemistry, well records, water sampling) are being assembled and 3D hydrodynamic models are being developed. Objectives are to (1) include produced water aspects in budget, (2) ascertain effects on surface water, and (3) determine if in situ permeability effects (reactive chemistry) are significant.
Produced Water Initiative, BLM Farmington. New produced water standards have been proposed. In the proposed standards, allowable salinity (TDS) varies with the intended use (new road construction or re-construction, road maintenance or seeding). BLM is waiting for industry proposals for pilot projects. Proper baseline studies (soils analyses, water composition, acceptable sodium adsorption ratios) are required in proposed pilots. Results from pilot projects may affect future water standards. Surface discharge is not being considered as an option.
Improved Oil Recovery
In the U.S. some 377 billion barrels of oil will remain in discovered reservoirs after conventional production. DOE's reservoir efficiency program strives to advance technology in chemical flooding, thermal methods, gas flooding, microbial, and other novel methods. Polymer gels for managing water production and/or improving reservoir sweep are one important IOR tool. DOE supports polymer gel R&D at the University of Kansas, the Petroleum Recovery Research Center (PRRC) at New Mexico Tech, and the University of Southern Mississippi.
Strategy for Attacking Excess Water Production (SPE 70067 by Seright et al). This strategy advocates that the easiest problems should be attacked first and diagnosis of water production problems should begin with information at hand. Water shutoff solutions can be chemical (gels, polymer/mobility-control floods) or mechanical (cement, sand, packers, bridge plugs, horizontal, pattern flow control). Of primary importance, one must determine if there really is a problem. Sudden increases in water cut in individual wells or areas of a field exhibiting higher than average water cuts point toward problem areas. Diagnostic testing such as pressure testing, production logging, use of chemical tracers and borehole televiewers can further diagnose the problem. In diagnosing the problem, it is important to determine whether flow is linear (fractures, channels) or radial (through matrix). One should also evaluate crossflow, which requires an understanding of the reservoir architecture or plumbing.
Excess water production problems and treatment categories can be grouped into four categories, with the preferred solution depending upon the problem:
Water Shutoff Using Polymer Gels in Fractured Producers (Sydansk). Polymer gels are one option for water shutoff treatments in producers in fractured reservoirs. Chromium carboxylate/acrylamide polymer (CC/AP) gels have been proven to form robust, relatively strong gels that are relatively inexpensive. Case studies in several areas (Rocky Mountains, Texas, Midcontinent) confirm profitable application when properly applied. Experience indicates they can selectively treat fractures, be placed deeply in fractures (whereas cement cannot), and tend to be placed in the most offending fractures. Although reducing water production, gels do not completely close off fractures, allowing oil production to continue through the fracture network. Treatment rate affects placement, with maximum rate maximizing placement depth and minimum rate maximizing gel strength. Both the volume and type of over displacement fluid affect treatment effectiveness.
Insights from 15 years of industry experience reveal that correct diagnosis of the problem, quality control of the gel/treatment, and operator involvement strongly influence success rate. With the importance of correct diagnosis, diagnostic testing to more specifically define the problem is often advisable. Experience indicates that real-world problems are often more complex than just fracture versus matrix. Polymer gels should be displaced far enough from the wellbore to permit acceptable and required oil inflow and far enough so that critical pressure gradient for gel flow is not exceeded, but yet gel must not be displaced so far as to permit excessive water inflow. Although each well is unique, there are often similarities in a given reservoir/formation within a geographic area and preferred practices for a given area evolve. Actively working together, operators and polymer gel technology providers can rapidly move up the learning curve to achieve greater than 90% success rates.
At PRRC Sydansk is conducting R&D that is focused on improving the performance and the strength of polymer gels for application to multi-darcy fracture-like flow channels that are conduits, in many cases, for excessive water production. An emerging trend is combining gel with stimulation operations. Some field results in Rockies reservoirs indicate that combined gel/stimulation treatments have been quite effective, indicating potential for much broader application.
Jerry Casteel
US DOE National Petroleum Technology Office
One West Third Street, Suite 1400
Tulsa, OK 74103-3519
Phone: 918-699-2042
Email: Jerry.Casteel@npto.doe.gov
Dave Mankiewicz
Bureau of Land Management
Farmington, NM
Will Palmer
Read & Stevens Production
P.O. Box 1719
Lovington, NM 88260
Phone: 505-396-5391
Mike Whitworth
University of Missouri-Rolla
Geological Engineering Department
1870 Miner Circle
Rolla, MO 65409-1060
Phone: 573-341-4867
Email: mikew@unm.edu
Sandia National Laboratories
P.O. Box 5800
Albuquerque, NM 87185-(mail stop #)
Mike Hightower
Phone: 505-844-5499
Email: mmhight@sandia.gov
MS # (0710)
Allen Sattler
Phone: 505-844-1019
Email: arsattl@sandia.gov MS # (0942)
Petroleum Recovery Research Center, New Mexico Tech
801 Leroy Place
Socorro, NM 87801
Phone: 505-835-5142 Fax: 505-835-6031
Martha Cather martha@prrc.nmt.edu
Brian McPherson brian@nmt.edu
Randy Seright randy@prrc.nmt.edu
Bob Sydansk rdsydansk@msn.com
Dr. Robert Lee, Director, Petroleum Recovery Research Center,
New Mexico Institute of Mining and Technology
801 Leroy Place-Campus Station
Socorro, New Mexico 87801
Martha Cather, Coordinator
Phone: 505-835-5685 Fax: 505-835-6031
Email: martha@prrc.nmt.edu
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