Sourcing water for large multifracture stimulations in west Texas is a well-known constraint on oil and gas activities in the area. A 6-month pilot operation demonstrated that produced-water reuse is technically feasible and can be a cost-effective solution. This paper summarizes the benefits of using a bipolymer crosslinking system in environments where water quality cannot be guaranteed. It also demonstrates the yielded cost savings per well that are achievable when reusing 100% produced or flowback water for hydraulic fracturing. This paper reports the completion of a two-lateral well in the Williston basin where produced water (PW), filtered but otherwise untreated, was used throughout the slickwater and crosslinked components of approximately 60 hydraulic-fracturing stages.
This paper describes a coreflooding program performed with sandpacks at different permeabilities, water qualities, and injection conditions. ProSep’s Osorb Media Systems are providing a unique solution for treating the water coming from chemical enhanced oil recovery operations and removing the dissolved hydrocarbons. Rising oil production in the Permian Basin has created an opportunity for midstream companies to acquire and expand pipeline infrastructure to handle a predicted spike in produced water. The company makes good on a pledge to reduce freshwater use and replenish the fresh water it uses. In a recent acquisition, H2O Midstream will own and operate Encana’s produced-water gathering system in Howard County, Texas, and will expand it to also serve third parties.
Travers, Patrick (Dolan Integration Group) | Burke, Ben (HighPoint Resources) | Rowe, Aryn (HighPoint Resources) | Hodgetts, Stephen (Dolan Integration Group) | Dolan, Michael (Dolan Integration Group)
Scope: The management, treatment and disposal of hydraulic fracturing flowback fluids and produced water presents a major challenge to operators. Though the volumes of water are tracked closely during operations, the sources of that water are not well understood. The objective of this study is to apply a cost effective and proven technique, stable isotope analysis, along with an extensive sampling program (n>1,500 samples) to describe the contributions of variable water sources through completions, flowback and the production lifecycle of multiple horizontal, hydraulically fractured wells in the Denver Basin, Colorado.
Methods: The water stable isotopes of hydrogen (1H and 2H) and oxygen (16O and 18O) are conservative tracers and particularly advantageous because they occur naturally in these systems and rely on well-established scientific and analytical techniques. Sample collection is simple and does not require specialized equipment or operational downtime. 80 horizontal, hydraulically fractured wells completed in the Cretaceous Niobrara or Codell Formations were selected for this study. More than 1,500 samples were collected and analyzed in total, including: baseline samples of the source water used to stimulate the well, time series samples collected at daily or semi-daily intervals during the early weeks of flowback, and samples collected several months after the wells were brought on production. Samples of produced water were also collected from legacy wells in the field as well as offset wells being monitored for frac hits during completions.
Results: Samples of the near surface and shallow aquifer source water collected prior to hydraulic fracturing fell on or near the global meteoric water line (GMWL) as defined by Craig (1961). This isotopic signature is expected for modern water in aquifers charged by precipitation. In contrast, samples collected during flowback and production were significantly enriched in 2H and 18O. Furthermore, the magnitude of the isotopic difference between the source and flowback water increased with time until equilibrating after several months. This equilibrated composition is consistent for Niobrara and Codell wells in the field, as well as legacy wells sampled and consequently is hypothesized to be indicative of native formation water. The study did find exceptions, particularly with wells known to be connected to major fault or fracture networks. These samples deviated from typical formation water signatures, potentially indicating the migration of deeper sourced fluids or the vertical mixing of shallower fluids with Cretaceous waters.
Significance: The scale of this study is unique in the literature and provides novel and comprehensive insight into the dynamics of flowback and the sources of produced water in the Denver Basin. This study demonstrates that these data can clearly differentiate water injected during stimulation from native formation waters, as well as track the magnitude and duration of well cleanup. It can also identify wells that may be producing water with a unique composition due to fluid migration through faults or fracture networks or due to nearby well communication.
Hazra, Suchandra (Dynachem Research Center) | Madrid, Vanessa (Dynachem Research Center) | Luzan, Tatiana (Dynachem Research Center) | Van Domelen, Mark (Downhole Chemical Solutions) | Copeland, Chase (Downhole Chemical Solutions)
This paper provides a detailed evaluation of the impact that field source water chemistry has on the performance of friction reducers being used for hydraulic fracturing. In this research, correlations are established between friction reducer performance and source water chemical composition, allowing operators to shorten the learning curve within their fracturing operations, use the most appropriate fluid systems, and potentially mitigate job failures. Extensive testing has been conducted to evaluate friction reducer performance in the presence of different ionic components such as calcium, magnesium, iron and chloride. Performance testing was determined by varying individual ions, as well as using source waters from multiple field locations having total dissolved solid (TDS) levels of well over 100,000 ppm. Testing parameters included friction reduction, hydration rate via viscosity, and rheological characterization for viscosifying-type friction reducers. Principal component analysis was used as statistical tool to characterize the variation in water chemistry and to establish its relationship with friction reducer performance.
With the oil price market slowly recovering in recent months, hydraulic fracturing activity may increase at faster rates than previously expected. However, even with higher oil prices, operators in shale plays still face significant budgetary issues with regards to water management. As demand and usage increase, and salt water disposal wells (SWDs) fill to capacity, com panies looking to stay afloat will have little choice but to find alternative means to store and reuse their produced water. "Costs will go up, and the industry needs to be prepared," Piers Wells, chief executive officer of Digital H2O, said. "What this drives us toward is the con clusion that increased water reuse will likely be an operational necessity in a recovering oil price environment."
Sourcing water for hydraulic fracturing and disposing of produced water are well-known constraints and significant cost items in the development of shale formations in the Permian Basin. Utilizing a water life-cycle approach, some of the produced water can be treated and reused. However, there is usually more produced water than needed and some must be disposed, typically by injection into a disposal well. Whether the water is to be reused or disposaed, it must be treated to some extent. Given the volumes of water involved, treatment technology must be robust and inexpensive. This suggests that the selected technology should be tailored to the characteristics of the water and the quality requirements of the final purpose (reuse or disposal).
This paper starts with characterization of produced water from a few Permian shale fields and proceeds to the selection of appropriate conventional, robust and low cost treatment systems. Using this approach, fit-for-purpose treatment systems have been implemented in the field. Impairment problems with reuse and disposal of this treated produced water have decreased.
With the oil price market slowly recovering in recent months, hydraulic fracturing activity may increase at faster rates than previously expected. However, even with higher oil prices, operators in shale plays still face significant budgetary issues with regards to water management. As demand and usage increase, and saltwater disposal wells (SWDs) fill to capacity, companies looking to stay afloat will have little choice but to find alternative means to store and reuse their produced water.
“Costs will go up, and the industry needs to be prepared,” Piers Wells, chief executive officer of Digital H2O, said. “What this drives us toward is the conclusion that increased water reuse will likely be an operational necessity in a recovering oil price environment.”
This article examines some of the water management issues facing companies in the Permian Basin and the Bakken, two plays with different geologic features but similar needs to handle rising produced water volumes.
The downturn put stress on operators in the Permian Basin, but despite the financial difficulties hydrocarbon and water production remained at high volumes. Digital H2O, a company that specializes in oilfield water resource forecasts, claimed that this was primarily due to the large number of wells completed between 2012 and 2014. Over the same time period, water intensity has gone up. In a company webinar, Wells said that the amount of water used per well completion has increased, and more water has been generated per well and per horizontal foot of wellbore length.
While completion activity has led to an increase in water intensity in the Permian, the basin’s SWD capacity is facing heavy constraints in key areas. Wells estimated that the average pressure utilization for SWDs was 65% in 2016, with several wells reporting utilization approaching 100%.
Fig. 1 illustrates the average monthly water volume disposed in an SWD compared to the average pressure utilization for SWDs for each county in the Permian Basin. A range of 60% to 80% utilization is considered high, and anything above that is considered full utilization, meaning that the wells in that county cannot accept any additional water for disposal. Wells identified four counties—Gaines, Yoakum, Kent, and Hockley—that are either at high or full utilization, with several other counties nearing the lower bound of the high utilization range.
The safe and responsible development of oil and gas resources is essential to meet the complex energy demands facing us today and enhance public acceptance of expanding industry activity. While use of hydraulic fracturing and horizontal drilling techniques in shale formations has resulted in rapid growth in oil and gas production in the United States and a transformed world energy outlook, these practices have also presented concerns associated with impacts from industrial activities. Extracting energy from shale has required more complex hydraulic fracturing operations, with a corresponding increase in equipment, personnel and materials, including water. A comprehensive suite of technologies and best practices provides our industry with solutions to improve the efficiency of hydraulic fracturing operations, while addressing safety risks, environmental stewardship and community concerns. Environmental and social challenges are varied and significant, with community and regulatory stakeholders focused on reducing emissions, noise, truck traffic and water use while safeguarding water quality. The ultimate goal is to reduce the footprint of hydraulic fracturing activities and to do so at a reasonable cost, to ensure energy remains affordable for communities, industry and overall economic growth. Extensive research and development has produced cost-efficient technologies that support safe, environmentally responsible hydraulic fracturing operations.
Stephen Whitfield, Oil and Gas Facilities Staff Writer It is common knowledge that hydraulic fracturing operations require a lot of water, and as they have become a more vital element of the oil and gas industry, sourcing this water has proven to be a challenge for companies operating in tough terrain. Drought plagues much of the United States, a country with significant hydraulic fracturing activity, and operators have to take hydrology concerns into consideration when constructing facilities in these environments. In most cases, the solution means recycling produced and flowback water and diminishing, or eliminating altogether, the need for fresh water. Depending on the region and its specific challenges, operators are finding unique ways to address the water issue. In the past couple of years, new facilities have been built or repurposed with new technologies that may affect how companies work in water-stressed shale plays in the future.
It is common knowledge that hydraulic fracturing operations require a lot of water, and as they have become a more vital element of the oil and gas industry, sourcing this water has proven to be a challenge for companies operating in tough terrain. Drought plagues much of the United States, a country with significant hydraulic fracturing activity, and operators have to take hydrology concerns into consideration when constructing facilities in these environments. In most cases, the solution means recycling produced and flowback water and diminishing, or eliminating altogether, the need for fresh water. Depending on the region and its specific challenges, operators are finding unique ways to address the water issue. In the past couple of years, new facilities have been built or repurposed with new technologies that may affect how companies work in water-stressed shale plays in the future.