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Abstract This paper addresses an advanced oxidation and precipitation water treatment process employed as an on-the-fly fluid pretreatment during hydraulic fracturing operations. The water treatment technology will allow for substantial reuse of flowback and produced fluid while at the same time completely replacing liquid biocide and scale inhibitor fluid treatment during fracs. Additionally, the treatment process generates zero waste. To date, the technology has been used on hundreds of wells successfully treating over 17 million barrels. The paper will report on more than 2 years of field operations on hundreds of frac stimulations as well as numerous pilot operations in multiple shale plays. Dynamic tube-blocking tests show that the treated fluid will not deposit scale even after days of storage in an open frac tank. Field sample testing shows the injected brine has 3 to 6 log-cycle kill of sulfate-reducing and acid-producing bacteria populations. With the move toward environmentally safe chemicals, an economical process eliminating chemicals is a step forward for our industry. The equipment is purposely designed to segue directly into the fracturing process without interfering with service company pumping operations or having any compatibility problems with any service company products. Our paper will show definitive results from field operations of an economic water treatment system that will allow for a reduction in liquid chemical usage and closed-loop management of wastewater. The newest design would treat 80 barrels per minute, occupying a footprint roughly the size of a frac tank. The units can be deployed in tandem for higher flow rate requirements.
Sharma, Ramesh (ConocoPhillips, Water Solutions) | McLin, Kristie (ConocoPhillips, Permian Unconventional) | Bjornen, Kevin (ConocoPhillips, Global Wells) | Shields, Austin (ConocoPhillips, Permian Conventional) | Hirani, Zakir (ConocoPhillips, Water Solutions) | Adham, Samer (ConocoPhillips, Water Solutions)
Abstract ConocoPhillips is committed to creating a responsible water management plan in developing assets in the Permian Basin of West Texas. Sourcing water for the large multi-frac stimulations in West Texas is a well-known constraint on oil and gas development activities in the area. Additionally, large volumes of produced water (PW) have traditionally required clean up and disposal in injection wells. Rather than viewing these constraints only as challenges, ConocoPhillips realizes the tremendous opportunity to address both issues by treating and reusing PW for hydraulic fracturing operations. With this perspective, water management strategy development has become a truly collaborative, cost-effective, and integrated process that addresses the full life-cycle of water. ConocoPhillips executed a multi-well reuse pilot program in the Permian Basin. A "fit-for-purpose" treatment scheme was deployed to selectively remove free oil, suspended solids, hydrogen sulfide, and iron as well as to inactivate microorganisms. While gravity separation was adequate for de-oiling and filtration for suspended solids, oxidation followed by coagulation and clarification was necessary for dissolved iron removal. The treated water iron concentration was below 5 mg/L whereas the turbidity was consistently below 10 NTU, making it suitable for well completions. When treating for H2S removal, the oxidation followed by filtration method was sufficient to reduce the H2S concentration to <0.2 mg/L and achieve turbidity below 10 NTU. The treated PW was compatible with the new salt-tolerant friction reducer, achieving similar friction reduction compared to a standard friction reducer and fresh water. The treated PW used in hydraulic fracturing was also compatible with formation water as it was produced from the same formation. The sulfate reducing bacteria were non-detectable in the treated water after four weeks of storage. The six month pilot operation, demonstrated that PW reuse is technically feasible and can be a cost-effective solution compared to other available water sourcing alternatives. The technical approach developed allowed use of salty produced water (>220,000 mg/L TDS) for completion activities utilizing a new type of friction reducer. Based on the success of the pilot program, a full-field produced water reuse program has been initiated early in the appraisal and development phase of the project to reduce implementation risks and improve economics in a safe and environmentally responsible manner. Strong collaboration led to success in these projects, and they were designed and executed through a significant team effort made by completion engineers, water treatment engineers, the asset development team, and the operations team. This paper provides an overview of the plan implemented for safe pilot operation, procedures for treatment of produced water and water quality results.
As the demand for water volumes needed to complete wells increase, limitations on freshwater availability and increasing water disposal costs, are driving produced water re-use efforts. These waters must be treated to reduce potential of damage to the formation and to ensure compatibility of other fracturing chemical additives. While treatment methods can improve chemical compatibility, the variability of the water composition presents challenges in selection of friction reducers (FR). FRs are the main component of Slickwater fracturing fluids and their performance impacts the ability to achieve desired pump rates. Changes in water quality can negatively affect friction reduction and lead to an increase in chemical usage and associated costs. Current methods for selection vary by equipment and those laboratory results have limited correlation with field results. This work outlines the methodology for monitoring produced or recycled waters during hydraulic fracturing operations, the evaluation of friction reducer performance in the laboratory and subsequent successful field validation.
Process evaluation and optimization showed that a unified monitoring approach can generate data that allow the selection of fluids that can meet the changing water conditions in the field. Standardized criteria were used along with on-site monitoring and testing to track changes in water composition and the effect of water quality on friction reducer performance and dosage requirements. The data was used to validate field results and to provide input on fluid design changes during the fracturing process to improve efficiency and drive cost-savings.
Monitoring showed the water composition varied greatly from site to site, highlighting the need for an in-depth understanding of water composition. Friction reducer performance also varied from pad to pad on the same lease. Performance changes correlated with changes in water composition over the span of the hydraulic fracturing operations. This suggested that standardizing a fluid design based on prior water data does not always result in optimal performance. The ability to optimize FR selection to existing water conditions, could result in chemical and water treatment cost-savings to operators when produced waters are used.
The use of produced water will continue to present challenges in fluid design; however, with proper understanding of produced water composition and its impact on fluid chemistry, fluids can be optimized to work in changing conditions. Definition of lab-based performance criteria for friction reducer performance, allowed for the selection of top performers for field trial. These could then be systematically ranked based on cost and performance and validated in the field based on fracture pressures and volumes used. Hydraulic fracturing operations using the top performing FRs for the specific water conditions allowed to operators to use harsher produced water quality while reducing the total FR spend.
Abstract The method of stimulation employed at the Shell Groundbirch asset in the Montney tight gas play is the limited-entry slickwater hydraulic fracture. The original fracturing water specification was a simple filtering requirement and an allowable range of salinity. Considering the associated health, safety, security, and environment (HSSE) perspectives, costs, and perceptions with sourcing and disposing of water related to hydraulic fracturing, determining a fracturing water specification became critical. This paper will describe a concise and pragmatic approach for determining a new fracturing water specification and water handling system aimed at recycling flowback and produced water, while using as little fresh water as possible. This water specification case study is based on the industry considerations of hydraulic fracturing and water management, and their impacts on costs and the environment. This approach to determine a chemistry specification for slickwater hydraulic fracturing and handling considerations may be applied elsewhere to enable the optimization of sourcing and disposal, HSSE concerns, production impairment prevention, and cost reduction. The process of determining the water chemistry specification assessed bacteria, formation damage, scale, and friction reduction performance. After a year of consultation and experimentation, an improved, but still simple fracturing water specification was established. Chemical use includes a scale inhibitor in addition to the on-the-fly fracturing fluids of a friction reducer, a surfactant, and a biocide. Scale inhibitor usage depends on pH and iron content. Coupled with water chemistry considerations, an integrated team initiated an intrafield water handling system that first recycles flowback or produced water and uses fresh water only when brine volumes are insufficient. This paper will specifically address (1) a method to develop a water chemistry specification for slickwater fracturing, (2) a pragmatic means of forecasting water in tight gas developments, and (3) a means of integrating water chemistry and forecasting learning into application for pragmatic field development. Introduction Tight gas developments rely on hydraulic fracturing to produce gas at economically viable rates. One popular method of hydraulic fracturing is the limited-entry slickwater fracture treatment in which a number of perforation clusters are attempted to be simultaneously stimulated with a slickened water and proppant slurry in a number of stages throughout the wellbore. The implications of water in tight gas beyond hydraulic fracturing have been recognized at Shell Canada's Groundbirch development in the Montney play. Shell Canada's Groundbirch asset is located in Northeastern British Columbia, Canada, per Figure 1. The current land base consists of nearly 400 sections of Montney focused development of which about half are Shell's land held with Brion Energy, while the remainder are held jointly between Shell and other partners.
Oraki Kohshour, Iman (University of Wyoming) | Leshchyshyn, Tim (FracKnowledge/Fracturing Horizontal Well Completions Inc.) | Munro, Jason | Yorro, Meaghan Cassey (Forum Energy Technologies) | Adejumo, Adebola T (Halliburton) | Ahmed, Usman (Unconventional Oil and Gas Technology and Development and WellDog) | Barati, Reza (University of Kansas) | Kugler, Imre (IHS Markit) | Reynolds, Murray (Ferus) | Cullen, Mike (Ferus) | McAndrew, James (Air Liquide) | Wedel, Dave (Air Liquide)
Summary With increasingly stringent regulations governing the use of fresh water in hydraulic fracturing, operators are struggling to find alternative sources of fracture fluid for hydraulic fracturing operations. In some regions of the world where abundant fresh water is not available, such as the Middle East and China, using large amounts of fresh water for fracturing is not possible to develop fields. FracKnowledge Database tracking of USA water usage per well indicates that, on average, a well requires 3 to 6 million gallons of water, even up to 8 million for the entire life cycle of the well based on its suitability for re-fracturing. This depends on the number of fracturing stages and particular characteristics of the producing formation. The same industry sources also suggest that about 30 to 70% of injected water remains in the formation with unknown fate and potential consequences to formation damage. Sourcing, storage, transportation, treatment, and disposal of this large volume of water could account for up to 10% of overall drilling and completion costs. As a transition to a reliable and complete replacement for water in the fracturing fluid, mixtures of fresh water with produced and brackish water are being applied. On the other hand, waterless fracturing technology providers claim their technology can solve the concerns of water availability for shale development. These waterless or minimal water methods have been used for decades, but are higher cost than conventional water fracturing techniques and have usually been used in water sensitive formations that required the technology. This study reviews high-level issues and opportunities in this challenging and growing market and evaluates key drivers behind water management practices such as produced and flow-back water, waterless fracturing technologies and their applications in terms of technical justification, economy and environmental footprint, based on a given shale gas play in the United States and experience gained in Canada. Water management costs are analyzed under a variety of scenarios with and without the use of fresh water. The results are complemented by surveys from several oil and gas operators. With low economic margins associated with shale resource development, operators need to know which practices give them more advantages and whether waterless methods are capable of fracturing the wells at optimal conditions. Based on a high-level economic analysis of cost components across the water management value chain, we can observe relative differences among approaches. Our analysis does not consider the effect of fracture fluid on productivity, which can be considerable in practice. Bearing this limitation in mind, as one might expect, fresh water usage offers the greatest economic return. In regions where water sourcing is a challenge, however, the short-term economic advantage of using non-fresh water-based fracturing outweighs the capital costs required by waterless fracturing methods. Until waterless methods are cost competitive, recycled water usage with low treatment offers a similar NPV to that of sourcing freshwater via truck, for instance. Despite positive experiences with foamed fracturing techniques in Canada, and the potential improvements offered by these techniques, the technology is still challenging to apply in large scale fracturing jobs in the United States, primarily due to operators' perceived level of technology complications, safety, economics, and other logistics. However, if these emerging technologies become widely accepted, the development of shale resources, especially in those basins exposed to drought, has the potential to grow both nationally and internationally. Although environmentally friendlier than using fresh water, the environmental aspects of these technologies must be clarified and deserve closer examination. Such variables must be reviewed based on specific shale reservoir characterizations before implementation on a large scale, and there are numerous other supply logistics and HSSE-SR (Health, Safety, Security, Environment, and Social Responsibility) issues that need additional discussion. Conclusions regarding current and future shale development have been proposed based on results from comprehensive technical, environmental, economic, and regulatory evaluations.