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.
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.
As a result of recent innovations in horizontal drilling and hydraulic fracturing, shale gas has become an important global energy supply. However, water consumption and disposal issues associated with shale gas development, coupled with industry growth, are creating a need for sophisticated water management strategies. Current shale gas water management strategies fall into three key categories: disposal, re-use, and recycling. Disposal strategies involve sourcing fresh water for hydraulic fracturing and transporting all frac flowback and produced water to an injection well for disposal. Re-use strategies involve primary treatment of frac flowback, so it can be blended with make-up water for re-use as frac fluid. Recycling strategies involve treating the flowback to fresh water quality, either for re-use in hydraulic fracturing or for environmental discharge. This paper will analyze the total life cycle water management costs per frac by comparing the options and costs of water supply; water transportation; cost and options for disposal, re-use, and recycling; impact of water quality on frac chemical costs; the impact of water quality on frac performance and long-term well performance. This paper will also identify other impacts, including safety, public perception, community impact, and environmental liability.
"When the well is dry, we know the worth of water.?? ? Benjamin Franklin.
Water management typically make up between 5% and 15% of overall shale gas drilling and completion costs. When we understand the short and long term considerations that contribute to overall costs, we know the worth of shale gas water management. Understanding the variables that influence flowback quality and quantity are a key foundation to establishing an overall strategy. Cost components, such as fresh water, transportation, storage, treatment options, and disposal, are highly dependent on the nature of the flowback, and both regional geography and regulations. There are three basic shale gas water management strategies: disposal of flowback, re-use of flowback, and recycling of flowback. A simple economic model can be used to determine the most cost-effective strategy, depending on the specifics of a particular scenario. A proactive shale gas water management strategy can both reduce costs and enable long-term production by addressing and balancing the needs of industry, the regional regulators, the environment, and the community.