WATER MANAGEMENT. FracFocus Turbocharged! KNOW YOUR WATER. Keeping the Water Lines Open in Freezing Conditions. When and What to Treat

Transcription

1 WATER MANAGEMENT SHALE PLAY Responsible Solutions for North America s Oil and Gas Industry ShalePlayWaterManagement.com November / December 2013 KNOW YOUR WATER When and What to Treat FracFocus Turbocharged! Air Emission Strategies for Flowback/Produced Water Treatment PART 2 Keeping the Water Lines Open in Freezing Conditions PLUS Case Studies, Latest News and More!

2 Know Your Water: Evaluating Characteristics of Source, Flowback and Produced Water for Effective Treatment While water treatment is not a new science, reusing produced water for hydraulic fracture fluids presents several new challenges not addressed by current state-of-the-art technology used in industrial applications. The key to success is in understanding when to treat and which components of the water to treat for effective reuse. A Baker Hughes H2prO engineer tests water quality during treatment BY KE NT DAWSON, D A R Y L MC C R A C K E N A N D ST EV E M O NRO E, BA K ER HUGHES Using incompatible waters or additives can compromise a hydraulic fracturing job and decrease a well s production potential. INTRODUCTION For the past one hundred years, industrial applications dominated the water treatment landscape. Water treatment technology research and development focused on increasing the efficiency of the world s chemical plants and refineries. When the oil and gas industry started examining recycling water, great comfort was taken in the volume of mature technology that was available. The belief that the technology could be borrowed from the industrial world, put on wheels, and be ready to treat produced and flowback water for hydraulic fracture fluids was common. Unfortunately, it wasn t that simple! While water treatment is not a new science, reusing produced water for hydraulic fracture fluids presents several new challenges not addressed by current state-of-the-art technology used in industrial applications. Whereas industrial 16 Shale Play Water Management water is controlled to meet strict specifications, the quality of produced water varies over a well s life cycle. Water produced during the first few weeks of a well s life, often called flowback water, is relatively clean and closely resembles the water used to hydraulically fracture the wells. After this flowback period, November / December 2013

3 Figure 1 Produced water quality changes dramatically with time. water quality rapidly decreases as contaminant-laden water from the formation begins to produce. This transition is neither linear nor predictable. In fact, water quality data gathered over a 12-month period at a produced water battery in a typical unconventional shale play showed an average variation of 13 percent for chlorides and 56 percent in total suspended solids (TSS). See Figure 1. The needs of the reservoir are also widely varied. Some reservoirs can be fractured with a turbulent proppant placement system, allowing the use of relatively dirty water, while others need to be fractured with a gelled system and much cleaner water. In addition to the fluid base, the chemistry of additives must be matched to the water being reused. Using incompatible waters or additives can compromise a hydraulic fracturing job and decrease a well s production potential. With the water and reservoir in constant flux, the objective of treating produced water is not to simply reuse the treated water, but to maximize the well s production across its life cycle. This requires knowledge of the reservoir and the fracture system, as well as water treatment and formation chemistry. GEOGRAPHIC KNOWLEDGE AND VARIATION The wide variability of water across many of our unconventional plays is well documented. In Figure 2, the solid boxes represent first through third quartile ranges of dissolved solid levels seen. The vertical lines above and below show the observed minimums and maximums. As a point of comparison, Figure 2 Typical TDS levels across the U.S. Continued Shale Play Water Management November / December

4 KNOW Your WATER the colored horizontal lines represent the total dissolved solids (TDS) levels permitted for various uses like drinking water, livestock or irrigation. But can high TDS levels cause formation damage or lower productivity? The answer is usually no, because typical fresh water used in hydraulic fracturing could almost be considered demineralized in terms of in-situ formation waters. In most cases, additional care must be taken when using the fresh water to avoid issues like clay swelling or scaling when the waters comingle in the formation. TDS 231,000 ph 4-7 Total Hardness (as CaCO3) 40,000 The challenge is to create an effective fracturing fluid with the desired operational characteristics using produced or flowback water. Solutions such as polyacrylamide-type friction reducers are fairly immune to high TDS levels, and produced waters with TDS levels of 231,000 ppm have been used successfully. However, the same cannot be said for conventional fracturing fluids. The following chart (Figure 3) is representative of both the variability seen in produced waters and the changes in chemistry required to create a stabile fluid. Produced waters vary from region to region and throughout the life of the well. When a well is fractured using fresh or brackish water, the immediate flowback will be consistent with the water used in the fracturing operation. Over the following few weeks, however, the water downhole will comingle with the produced water until it stabilizes. Even then, the water will continue to vary (See Figure 1 on preceding page). PROBLEMS WITH TOTAL SUSPENDED SOLIDS Formation damage is a very real danger when dealing with high levels of TSS found in most produced waters. Formation damage can best be described as any obstruction or barrier in the near wellbore region that reduces the flow capacity of the rock. Formation damage comes in many forms, such as fines migration (like those found in produced waters), emulsion block, water block, clay swelling, and scale. A producing formation must have good porosity and permeability properties, and the near-wellbore area must not be damaged during drilling or completion or have a skin or radial that prohibits the free flow of hydrocarbons. If a hydraulic fracturing stimulation is performed using contaminated fluid as the mix water for the fluid, the small particles of solids mixing with the sand will take up the pore space between the sand grains, reducing permeability (Figure 4). The permeability of this mixture is actually less than that of the gravel pack with pure sand particles. Many operators fail to consider the impact of TSS or the actual size of particles in the water. A typical oilfield filter size of 20 or even 10 microns can do very little when most of the particles are smaller. The cost of using untreated water can be significant. In one case, the productivity of a compact zone was 45 percent with a perforation plugging loss of 13 percent. The combined effect in final productivity was 39 percent of the original value. With undamaged production at 500 bbl/day, this equated to a production loss of 305 bbl/day. At USD 80/bbl, first year revenue loss was significant. CLAY SWELLING Clay swelling occurs when water devoid of dissolved mineral content (fresh water) comes into contact with reactive clay, Figure 3: Acceptable ranges of TDS and hardness for varying temperature x-link hydraulic fracturing fluid systems (Baker Hughes) 18 Shale Play Water Management November / December 2013

5 KNOW Your WATER Figure 4: Suspended solids reduce proppant permeability such as Illite or Montmorillonite. The resulting swelling can block pore throats and decrease production until the offending water is exhausted. 1 The addition of clay swelling inhibitors can help mitigate potential damage, but when using produced water, this becomes unnecessary. Most produced water is from the same geological beds being hydraulically fractured, and the water is essentially identical to the in-situ water, resulting in no clay swelling. TO TREAT OR NOT TO TREAT? While many an entrepreneur has looked at the vast perceived opportunity of flowback treatment with starry eyes, the reality is a bit more sobering. Simply, there is no one-size-fits-all magic bullet treatment to convert all flowback or produced water into a reusable product consistently and economically. Despite the hundreds of innovations that have appeared on the market over the last few years, few have demonstrated sufficient, consistent success to meet the market needs. The key to success is in understanding when to treat and which components of the water to treat for effective reuse. Much of the perceived market is already served. While estimates vary, one of the most comprehensive studies 2 suggests that over 21 billion bbl of produced water are generated annually and that more than 55 percent of this is reinjected for enhanced recovery. Despite the development of unconventional programs, which require more water initially than with conventional oil and gas development, the market for oil-water separation, solids removal, and bacterial treatment is already well established for management of these water volumes. Yet, a renaissance in water is taking place that leverages experience with produced water and applies that to the desire to more effectively address water for and from hydraulic fracturing. Water treatment is well understood, and there are a host of methods proven for addressing particular needs in the oilfield and other industries. However, to meet the technical and economic requirements of produced and flowback water treatment for reuse, it is helpful to look first at the broader picture. Critical to successful reuse is an understanding of the technology options and their limits; transportation, storage, and logistics costs; and the social, environmental, and economic requirements. SUSTAINABLE SOLUTIONS SATISFYING SOCIAL, ENVIRONMENTAL, AND ECONOMIC REQUIREMENTS Truly effective solutions meet both the technical requirements and address the social, environmental, and economic needs. While the amount of water used by the oil and gas industry is less than 2 percent of the overall annual water use in the U.S. 3, reducing the volume of fresh water still provides a great deal of benefit environmentally, especially given the drought conditions in many parts of the U.S. By reusing produced water at or near its source, we also reduce the potential traffic, vehicle emissions, noise, and road damage often associated with traditional water sourcing and disposal. Such a reduction in transportation also has a direct economic benefit. COST OF TRANSPORTATION AND STORAGE The most significant cost of any water management program is associated with moving and storage of this resource. Trucking remains one of the primary methods of moving fluids to and from the well site with estimates of 500 to 1500 truckloads per well. 4 Typically, water trucks carry between 80 and 130 barrels with average charges of $100 per hour or roughly $1/bbl/hr. Factor in the twenty to thirty minutes to both load and unload a truckload of water, a minimum cost of $1/bbl is a certainty. Since most lease road traffic is rather slow (20 mph) from necessity, safety, and regulation, even more travel time costs are incurred. This doesn t take into account traffic and idling as trucks wait in line to either fill up or unload their water. When all these factors are combined, the costs are staggering. One major producer estimates that 25 percent of their typical well costs are associated with moving water in the Marcellus. 5 The University of North Dakota estimates that percent of total water costs are associated with transportation in the Bakken. 6 Continued Shale Play Water Management November / December

6 KNOW Your WATER ONE SIZE DOES NOT FIT ALL ROBUST SOLUTIONS FOR DAILY VARIATION OF WATER Water changes from field to field, well to well, and day to day, which complicates any treatment regime. Treatment typically falls into a few broad areas: Basic separation Membrane separation Thermal Adsorption Oxidation/disinfection Each of these categories has a host of technical solutions, but each also has limitations. Unfortunately, the constituents commonly found in produced water often exceed the acceptable limits of these treatments or require a combination of treatments. And, the variability of this water further impedes treatment, adding even more cost and complexity to any treatment process. Only the most robust solutions can meet these challenges. At the same time, recognizing what to treat and what not to address can greatly benefit the operator technically and economically. For example, oil and grease can be removed from produced water through a host of basic separation technologies. By improving the existing separation technology at the wellhead, more oil will be gathered, while at the same time enabling easier treatment of the waste water. Salts, or TDS, are another key component of produced water that often exceeds the salinity of seawater by five to ten times. While technologies exist to remove these salts, they are not the best option. Reverse osmosis is commonly used to desalinate seawater, which contains approximately 30,000 to 40,000 parts per million TDS, but it cannot address higher salt concentrations of produced water effectively. Evaporation can also effectively remove salts where the costs of transportation and disposal are quite high. This is a critical factor as the energy costs are also quite high for evaporation. Unfortunately, extensive pretreatment may also be required to remove oil and grease, hardness, and suspended solids. This adds significant costs so only a very narrow range of produced waters is suitable for evaporative technology. Only by understanding fully the water characteristics and reuse requirements can the right solutions be reached. For example, the Baker Hughes patent-pending H2prO HMS (Heavy Metal and Solids) service uses a unique type of electro-chemical precipitation to treat produced water. It removes formation-damaging suspended solids, even at the single micron range where filtration fails. Iron is also removed, which can cause significant damage to the formation of stable hydraulic fracturing fluids. Iron, too, is typically less than 1 micron in size, rendering standard filtration ineffective. The following example (Figure 5) is a particle size distribution chart of unfiltered water an operator wanted to run through a 20 micron filter. In this example, however, 90 percent of the particles were <10 microns. This process also reduces hardness and TDS by approximately 20 percent and can have up to a 3 log kill of bacteria, which in turn reduces the need for additional chemicals in the hydraulic fracturing fluid. Figure 5: Typical particle size of water before (raw) and after H2prO HMS treatment Continued 20 Shale Play Water Management November / December 2013

7 KNOW Your WATER 4 King, G. E. Hydraulic Fracturing 101: What Every Representative, Environmentalist, Regulator, Reporter, Investor, University Researcher, Neighbor and Engineer Should Know About Estimating Frac Risk and Improving Frac Performance in Unconventional Gas and Oil Wells. SPE Ellis, S Oilfield Water Management: The Oil and Gas Industry s Holy Grail. Seeking Alpha. oilfield-water-management-the-oil-and-gas-industrys-holy-grail The H2prO units can be rigged up in less than two hours. Water should be looked at holistically over the life of the field. Once it has been treated, for what will it be used? How long can it sit in the hot sun before treatment is ineffective? A properly planned and executed water management program can reduce operating expenses, reduce the demand for fresh water, and improve production. CONCLUSION Until recently, the hydrocarbon business was easier. Oil and gas were pumped out of the ground, separated from water, and processed into fuel or electricity. Produced water was reinjected to maintain pressure or disposed of through deep well injection. Unconventional oil and gas development, especially horizontal drilling and multistage hydraulic fracture, have driven a paradigm shift in both the water required to complete a well and the volume of wells required for economic viability. This drastic increase in well and water volumes has propelled water management to the forefront of technical, regulatory, and policy discussions. It s not enough to be smart about water treatment, or fluid chemistry, or production enhancement as independent activities. It is the marriage between them that creates real value, saving money. Through intelligent reuse, shut-off, and control of water, we can transform water from a burden into a benefit, increase production, and extend the economic life of assets for years to come. REFERENCES 1 Porter, K.E An Overview of Formation Damage. J. Pet Tech. 41 (8): Veil, J.A., and Clark, C.E. Produced Water Volume Estimates and Management Practices. SPE United States Geological Survey. Estimated Use of Water in the United States in April 2010 report, Bakken Water Opportunities Assessment Phase 1, the University of North Dakota s Energy and Environmental Research Center (EERC) About the Authors: Kent Dawson is currently the Director of Water Management at Baker Hughes. He started the water management business at the company in 2010 and is responsible for engineering, product development and M&A. Mr. Dawson has built his career around energy. From efficient fuel cells to clean coal and diesel emissions treatment, he has spent his career commercializing clean energy solutions. He has a PhD, MS, and BS in Chemical Engineering as well as a MBA. Daryl McCracken has been with Baker Hughes for nearly 14 years. His previous roles include project management, marketing and product line management helping develop new products in drilling, formation evaluation and completions. In 2010, he helped establish water management as a new product line and currently serves as the Engineering Manager for Baker Hughes Surface Water Treatment group. Steve Monroe has more than 32 years of experience in the oilfield service industry in varying roles in drilling systems and product development. He is currently the Product Line Manager for Surface Water Treatment in the Baker Hughes Water Management group. In this role, he is responsible for the business decisions in selecting and delivering new technology and products to serve this growing market. 22 Shale Play Water Management November / December 2013

8 Don t let water-related costs drown your bottom line H2prO experts developed a plan for treating and reusing produced water that significantly reduced the operator s trucking and disposal costs without impacting oil production. 400 No one knows H2O like we know H2O 2013 Baker Hughes Incorporated. All Rights Reserved /2013 New production methods, limited resources, proliferating regulations, recycling produced and flowback water Effectively managing your water is critical to both reservoir performance and ROI. With our holistic H2prO water management service, we ll study your water issues and deliver customized, turnkey solutions providing valuable insights across your usage cycle. The results are more efficient stimulation and production with less waste and lower disposal costs. Contact Baker Hughes and let us design an H2prO solution that benefits your bottom line. Advancing Reservoir Performance Fresh Water Requirements (truckloads) Wastewater Disposal (truckloads) Before H2prO HMS service With H2prO HMS service bakerhughes.com/watermanagement