Hydraulic fracturing solutions use a gelling agent known as guar gum to transport proppant. Flowback water can have guar gum concentrations has high as 1% by volume creating treatment challenges prior to reuse or disposal. In this second article of a series covering water management in hydraulic fracturing (HF) in unconventional resources, the properties and characteristics of the flowback fluids are discussed, together with the general categories of technologies that are best suited to treat them.
The well count and completion intensity of US tight oil and gas operations have grown in recent years, and rising pressure from environmental regulations means that produced water management has become a key focus for operators. While storage and logistics are critical elements of the viability of water reuse, if the water chemistry is not fit for gel fracturing formulations, it will not matter how much is stored in centrally located impoundments. This paper reports on performance of an advanced MVR system in north-central Texas. With inconsistent inlet water quality being the rule rather than the exception, sizing and operational considerations of the treatment system components must vary accordingly to make the most economic sense. The demands for the fresh water used in many hydraulic fracturing operations are placing pressure on water sources in some regions of the United States.
Researchers from Chevron are looking into a new approach to understand the drivers of polymer hydration. How might this affect the design of mixing systems in the field, and could it affect offshore EOR applications? Fluid Efficiency and Rhapsody Venture will partner to refine and launch a new molecular technology to improve the flow in pipelines. In this second article of a series covering water management in hydraulic fracturing (HF) in unconventional resources, the properties and characteristics of the flowback fluids are discussed, together with the general categories of technologies that are best suited to treat them. This is the first of several articles on the subject of water management for unconventional hydraulic fracturing.
As producers push logistical and technological limits to operate in deeper water and more remote locations, maintaining and repairing offshore structures can present a number of challenges unique to these environments. One of the costliest is corrosion. In this second article of a series covering water management in hydraulic fracturing (HF) in unconventional resources, the properties and characteristics of the flowback fluids are discussed, together with the general categories of technologies that are best suited to treat them. Higher oil prices has created increased interest in chemical enhanced oil recovery (CEOR) using polymers, surfactants, and alkalis. This technology poses some special challenges, especially around water treatment.
A joint-venture agreement gives Solaris control of Concho’s produced-water infrastructure in New Mexico, and Lagoon Water Solutions closed on a deal with Continental in Oklahoma. Getting water is a big issue for those who fracture wells, as is the disposal of it. The number of companies investing in water facilities and reuse, though, remains a minority. Water Outside the Permian: How Are Other Basins Handling the Volumes? The Permian gets the lion’s share of attention when it comes to produced water, but other basins have a need to haul volumes off-site.
The deal sees H2O Midstream increase its produced water gathering network to more than 435,000 B/D of disposal capacity and 190 total miles of pipeline. The Permian water midstream company will add more than 40,000 B/D of recycling capacity with the option to double that capacity over time. A joint-venture agreement gives Solaris control of Concho’s produced-water infrastructure in New Mexico, and Lagoon Water Solutions closed on a deal with Continental in Oklahoma. Getting water is a big issue for those who fracture wells, as is the disposal of it. The number of companies investing in water facilities and reuse, though, remains a minority.
Jones, Drew (Deep Imaging) | Pieprzica, Chester (Apache Corporation) | Vasquez, Oscar (Deep Imaging) | Oberle, Justin (Deep Imaging) | Morton, Peter (Deep Imaging) | Trevino, Santiago (Deep Imaging) | Hickey, Mark (Deep Imaging)
We used a new, large-scale, surface-based, controlled-source electromagnetics (CSEM) approach to map the locations of frac fluid during flowback following a three-well hydraulic fracture stimulation in the Permian Basin. CSEM records and analyzes electric field signals induced in the electrically conductive frac fluids by a surface-based transmitter. For this study, we placed a grounded dipole transmitter directly above the central horizontal well of three parallel neighboring wells. The transmitted signal was a broadband pseudo-random binary sequence. To record the frac fluid response signal, we placed an array of 161 receivers on the surface covering the three horizontal wells. We recorded the induced, response signals of the flowback fluids in three-hour intervals (three on, three off) for 228 hours. The CSEM recording started eleven days after flowback began on the central well and four days after flowback began in the two outer wells. From this time-lapse recording we captured the spatial and temporal change in electrical conductivity within the fractured reservoir, allowing us to infer the location of flowback fluid and its movement. During the stimulations chemical tracers had been included in the frac fluid. Analysis of the tracers captured during flowback agreed well with the mapped fluid locations and movement found in the CSEM data.
Flowback monitoring and its interpretation offer another valuable tool for frac and reservoir engineers. This understanding is especially critical in developing and managing unconventional reservoirs. Here, the stimulation responses are not simple, more and more evidence show complex fracturing and complex fracture networks (e.g., Rassenfoss, 2018). Characterizing a fracture network or networks in shale (i.e., an unconventional reservoir) is a challenging task. It is complicated by multiphase and complex flow regimes, non-static permeability and porosity, natural fracture and flow systems, heterogeneities and complex stress, changing stress with production, liquid loading, and a host of operational concerns (Zolfaghari et al., 2016). In the past, to determine hydraulic fracture properties, operators used production data in a variety of models to manage wells and reservoirs. Garnering production data can take months or even years delaying, for example, upgrades to well and stimulation designs and designing infill drilling (Williams-Kovacs, Clarkson, & Zanganeh, 2015). In contrast, a flowback occurs during the transition between stimulation and bringing the well online. Understanding the flowback provides significant improvements in determining early production rates enabling estimates of the effective size of stimulations, distinguishing key reservoir properties, and predicting long-term production rates (Jacobs, 2016). In addition, there can be direct savings if, for example, flowback interpretation identifies an underproducing play in time to redirect funds into a more lucrative play before infill drilling (Williams-Kovacs et al., 2015).
Li, Ningjun (Haimo Technologies Group Corp.) | Zheng, Ziqiong (Haimo Technologies Group Corp.) | Guo, Peihua (Haimo Technologies Group Corp.) | Hao, Xipeng (Haimo Technologies Group Corp.) | Chen, Bingwei (Haimo Technologies Group Corp.) | Ren, Yao (Haimo Technologies Group Corp.)
Ordos basin is known for its tight sandstone formations and fracturing has been the most effective approach to improve production[
To successfully treat and reuse flowback fluid in Ordos basin, two major obstacles have to be overcome: First, in the fracturing process, the local common practice is to add the entire designed amount of gel breaker at the end of propant pumping job, to avoid sand plugging and sanding out. This incorrect, but common practice results in incomplete breaking of gel of the frac fluid, which inevitably flows back leading to greatly increased difficulties in flowback fluid treatment. Secondly, organic boron crosslinking agent is widely used as crosslinking agent in the guar fluid system in this area. As boron compounds are extremely difficult to be removed during flowback fluid treatment, proven treatment methods alone cannot make the treated water reusable in making new frac fluids.
Technology and processes were developed to manage four key factors that affect the performance of guar frac fluid configured with treated flowback fluid: a) Metal ions, b) Bacteria, c) Breaking agent, d) Crosslinker. Mobile units developed in association with treatment processes and agents also help avoid secondary pollution from the transportation of fresh and flowback fluid. In 2017 and first quarter of 2018, more than 15,000 cubic meters of flowback fluid have been successfully treated and reused. One third of the treated water was guar frac fluid and was reused in making new frac fluid, reducing the need for fresh water significantly. Fracturing service company conducted tests on the treated water and found that the performance of the fluid configured with the treated water completely satisfy the requirements of the SY/T6376-2008 "General Technical Requirements for Fracture Fluid" and SY/T 5523-2016 "Oilfield Water Analysis Method" standard. Frac fluid configured with the treated water was successfully applied to the stimulation jobs of horizontal wells, resulting in double savings to the operators: purchase of fresh water and transportation of flowback fluid (to treatment centers) and fresh water, also avoided secondary environmental impacts such road safety hazard and fluid seepage.
With the treatment and reuse of flowback fluid, savings up to 8% of total frac costs per well were observed which could lead to 100+ million RMB within 2018 alone. Most importantly, the technology can effectively relieve environmental pressure and reduce the need of fresh water which is a scarce in this area.
An area of great interest to those researching flowback is the interaction of water and salt inside the shale reservoir. After a well is stimulated, the flowback fluids tend to show a rising concentration of salt that falls back to near zero over time. The goal is to analyze this salt concentration curve to determine the complexity of a well's fracture network. This is important since complex fractures are estimated to have a flowing surface area of 50 to 1,000 times greater than a simpler, or planar, fracture. The applications for this area of study could be far reaching because nearly all North American shale plays were once covered by salty seas.
Jianxin, Peng (PetroChina Tarim Oilfield Company) | Mingguang, Che (RIPED-PetroChina, Key Laboratory of Reservoir Stimulation, PetroChina) | Guoqing, Zou (PetroChina Tarim Oilfield Company) | Jiangyu, Liu (PetroChina Tarim Oilfield Company) | Liao, Wang (RIPED––PetroChina, Key Laboratory of Reservoir Stimulation, PetroChina) | Rui, Gao (RIPED––PetroChina, Key Laboratory of Reservoir Stimulation, PetroChina) | Juan, Xie (RIPED––PetroChina, Key Laboratory of Reservoir Stimulation, PetroChina) | Leifeng, Meng (CNPC XiBu Drilling Engineering Co.Ltd) | Runqiang, Fan (CNPC XiBu Drilling Engineering Co.Ltd)
KeShen gasfield is a low matrix permeability intensely naturally fractured tight sandstone reservoir in Kuqa gasfield of Tarim basin, West China, with the characteristics of high-pressure 120MPa-140MPa, ultra-depth 6700m-8000m, high temperature 160°C-190°C, and long lateral 200m-300m. A non-acid stimulation was trialed in five wells and the post-production was surprised.
During drilling, a large number of barite is used to increase mud weight, and some calcium carbonate is used to avoid reservoir damage, But the damage is usually serious because of hundreds of tons of mud leakoff and the drilling fluid cakes. A non-acid cheating agent was trialed for removing the damage and increasing the production, based on the cheating mechanism, the divalent metal ions will be chelated by cheating agent, and barium or calcium ions will be preferentially chelated.
The non-acid cheating agent is an alkaline chelate with density 1.03g/cm3, the dissolving capacity of chelating barium ions is increasing by the chelating agent concentration and temperature. The concentration is usually from 25% to 30%, and the capacity of chelating barite ions is about 12.5-12.8g/L at the temperature of 170 °C. The reason for using chelating agent to remove the damage is that fresh acid and reacted acid can make strong corrosion to tubing string in the process of acidizing in high temperature reservoir. On the condition of 140 °C, the laboratory experiments indicate that the corrosion rate of fresh acid and the residual acid is 17.4g/ (m2·h) and 3g/ (m2·h) respectively, however, there is essentially no string corrosion observed when using the chealting agent for removing the damage. The non-acid cheating agent was trialed for five Wells. The general pumping rate is from 3.0 m3/min to 4.4m3/min, and the total volume of cheating agent is about 400m3. The gas post-production is about from 60×104 to 70×104m3/d, similar to that of adjacent wells to which acidizing or hydraulic fracturing are applied. The flowback fluid of the non-acid stimulation wells is tested, the results indicate that the maximum content of barium sulfate is 3200 mg/l, and the maximum content of calcium ion is 4382mg/l.
The non-acid stimulation is an effective method for high temperature intensely naturally fractured gas sandstone, no tubing corrosion.