The project goal is to develop a cost-effective water recovery process to reduce shale gas production costs and environmental impacts. This effort seeks to develop a hydrofracturing flowback water pre-treatment process and a membrane-based partial demineralization process for low-Total Dissolved Solids (TDS) flowback water treatment. The ultimate objective is the production of clean, reclaimed water suitable for re-use in hydrofracturing operations.
GE Global Research, Niskayuna, NY
Technological advances, such as the hydrofracturing (frac) extraction method, have permitted unconventional natural gas sources, such as shale gas, to make a dramatically larger contribution to the U.S. energy supply. Shale gas production in the U.S. has increased from 700 million cubic feet (MMcf)/day in 1998 to 4,800 MMcf/day in 2008, accounting for 6% of the nation’s supply. U.S. shale gas reserves estimates range from 470 to 630 trillion cubic feet (Tcf)—about 28% of total U.S. natural gas reserves.
Two significant shale development issues are (1) drilling and hydrofracturing water availability and (2) resultant produced hydrofracture waste water (otherwise known as “frac flowback water”) disposal options. The large volume of water usage is a major factor in the frac process, with 100 barrels of water (1 barrel = 42 gallons) used per million cubic feet (MMcf) of produced gas. Thus, for shale gas production in 2008, the water usage was approximately 480,000 bbl/day or 20 million gallons/day. Two-to-four million gallons of water are introduced into a well during typical drilling and hydrofracturing processes. Trucked-in fresh water constitutes a large part, and can be cost-prohibitive due to associated high transportation costs. Other water sources utilized to a lesser extent are local freshwater reserves (lakes, rivers, wells, etc.). The use of large quantities of water for gas production has become highly unpopular with the general public. Upon completion of the drilling and fracturing processes, approximately 20–80% of the water used returns back up the bore hole as frac flowback water and produced water. This water contains frac chemicals and a significant mineral content, and proper disposal protocols must be followed. Most flowback water is deep-well injected. However, there are few geographically convenient deep-well injection sites available to the typical operator. For example, most operators in Pennsylvania truck flowback water to Ohio for disposal at great expense ($10/bbl plus transportation) to the company. Development of a cost-effective process for treating produced/ flowback water, making it suitable for re-use, would be of great benefit to the industry from both an economic and environmental perspective.
The project has four key elements: First, a preliminary design study addressing recovery process alternatives, based on field flowback water analysis and gas well operation requirements, will be conducted to quantify the benefits of treating the low-TDS portion. Second, different high-flux membrane types will be evaluated for use in low-TDS water treatment. Third is the development of effective pretreatment processes for removal of suspended and dissolved contaminants capable of adversely affecting membrane performance and longevity. The final element is a techno-economic feasibility assessment of a mobile rig configuration. This evaluation will be based on bench-scale experimental data derived from field water samples and suitable performance modeling.
Successful completion of this project should provide the technical and economic foundation for the commercial reclamation/reuse of nearly all generated low-TDS shale-gas flowback water. This should be at a cost that is competitive with the costs associated with the current practice of trucking wastewater to deep-well injection sites. The project also has the potential to reduce the overall costs and environmental impact of shale gas production by significantly reducing fresh-water consumption, waste-water disposal, and water-transportation related traffic on roads.
A parametric value assessment tool has been developed to evaluate the economic merits of any Flowback Water Recovery Process (FWRP) relative to conventional disposal. There appears to be no clear consensus among operators on the specifications for frac water re-use in the short-term. Consequently, it was found necessary to update the product water scope from, initially, one product with 20,000 ppm TDS to potentially four alternative products with varying levels of purification:
These product options and the associated target contaminants for removal are shown in Figure 1. Product-3 above now represents the initial product target.
The team developed “verification of success” criteria for critical go/no-go decisions for this project: Water recovery > 95% for Product-1 and > 90% for Product-2. For flowback water with <40,000 ppm TDS, water recovery > 50% for Product-3 and > 40% for Product-4.
The team obtained frac flowback samples from wells in the Woodford shale in Oklahoma, and also from a pond that receives flowback waters from several frac operations in a midwestern shale play. The frac flowback samples that were obtained from the Woodford shale sites were analyzed in order to understand the composition profiles of the contaminants of interest as a function of the flowback time. The components in the flowback water of interest in this project are particulates (>5 µm), suspended solids (<5µm, colloids), free oil, dissolved organics, volatile organics, hardness ions (Ca, Mg, Ba, Sr, sulfates, carbonates), Fe, silica, and bacteria that may affect the product quality and/or the desalination membrane performance. These water samples are suitable for the experiments planned for assessing pretreatment and membrane options.
Based on the surveys of the TDS content of the flowback waters from different shales, the applicability of the low-TDS (< 40,000 ppm) recovery approach is as follows: In Fayetteville and Woodford, almost 100%, since the flowback has generally <40,000 ppm TDS. In Barnett, by selectively directing the flowback from the first 5 days of operation, ~30-40% of the flowback may qualify as low-TDS, but recovery may not be considered at all since disposal via underground injection is readily and cheaply available. In Marcellus, overall only a small fraction (<10%) of the flowback may be amenable to low-TDS recovery. However, 20–40% of the flowback may be amenable at certain locations with appropriate water management to isolate flowback water produced in the first 3~5 days of operation.
The team conducted bench-scale experimental evaluations of various mechanical, chemical, and membrane treatment options identified to remove undesired contaminants. These experiments have been successful in identifying process technologies and associated operating conditions for the removal of key contaminants pursuant to the product quality specifications for the alternative Products-1, -2, -3 and -4 (cf. Figure 1). These experiments were conducted with simulated waters with spiked contaminants but mostly with frac flowback field samples gathered from the Woodford shale described earlier. However, removal of some of these contaminants from frac flowback waters, especially the dissolved organic contaminants, proved to be a greater challenge, than anticipated. For Products-3 and -4, key membrane foulants, namely, inorganic compounds that could physically precipitate inside the membrane module and inorganic and organic contaminants that could foul the membrane surface, were shown to be successfully removed in these bench-scale experiments.
Using the information from the bench-scale experiments for the various pretreatment steps, detailed conceptual flowsheets for the treatment processes for each of the products (1–4) under consideration were constructed. These were evaluated for technical performance, costs, and mobility for a 50-gpm feed (frac flowback) mobile rig system. Technical performance evaluation included mass and energy balances, including waste generation and handling. Costs included capital expenses for equipment and assembly, and operating expenses for amortization of capital equipment, labor for rig setup and operations, rig transportation, chemicals, membranes, power, and waste removal. Mobility included the preliminary assessment of the rig configurations and footprint suitable to treat 50 gpm of the frac flowback water.
For Products-3 and –4 that require RO membrane desalination, key membrane foulants (namely inorganic compounds that could physically precipitate inside the membrane module and inorganic and organic contaminants that could foul the membrane surface) were shown to be successfully removed in these bench-scale experiments. For demonstration, RO membrane fouling experiments were conducted using commercially available 2” diameter spiral wound RO modules with 10 liters of pretreated Woodford Site-2 Day-26 35K ppm TDS flowback fluid sample over 24 hours at 800 psig and 25°C. The water-flux and salt-rejection vs. time profiles for this run were identical to those for a similar run with a “control” solution of 35K ppm TDS sodium chloride (NaCl) in deionized water. This indicated the effectiveness of the down-selected pretreated conditions in removal of potential membrane foulants.
A value-assessment cost model was developed for the overall FWRP for the Products -3 and -4 that use RO membrane desalination to compare with the conventional disposal method. The conventional disposals cost included transportation of all flowback water and injection in Class II saltwater disposal (SWD) wells while the FWRP cost included treatment costs, product delivery and remaining concentrate disposal (transport + SWD injection) costs. The sensitivities of the FWRP cost to prevailing concentrate disposal conditions were expressed as plots of CFWRP/CConventional vs. CDisposal at different feed TDS concentrations. The economical “cut-off” TDS is defined as that feed TDS concentration when CFWRP/CConventional =1. For Product-4 (500 ppm TDS), this “cut-off” TDS is in the range of 20,000 ppm to 65,000 ppm depending on the local saline water disposal costs. These sensitivity charts thus provide a means of comparing the relative value of FWRP for a well flowback treatment opportunity based on prevailing disposal costs and anticipated flowback TDS levels. Note that the other drivers, such as penalty avoidance or cost incentives from frac flowback re-use due to local regulations have not been considered. In some cases, these non-technical issues may be the economic driver for FWRP.
To increase the overall system water recovery, a hybrid membrane + thermal system was also considered. In this approach, the retentate (90,000 ppm TDS) from the membrane system is further concentrated by distillation in a mobile evaporator (such as that introduced by GE Water recently) to yield a distillate with <500 ppm TDS but more importantly, a concentrate with 280,000 ppm TDS. The Hybrid system yields higher recovery; for example, 85% for a feed with yF = 35,000 ppm TDS vs. 61% for the membrane rig alone. However, the hybrid process costs more than individual process options alone due to the high fixed costs for such small throughput (50 gpm) systems. The sensitivity plots of CFWRP/CConventional vs. CDisposal at different feed TDS concentrations show the dramatic decrease in CFWRP for the Hybrid due to increased water recovery. The membrane alone case is more economical for the lower CDisposal cases mainly due to the lower overall capital costs. However, the hybrid case becomes more economically attractive for the high CDisposal shale plays where local SWD sites are unavailable, thus leading to higher flowback water transportation costs for the conventional disposal method.
It is concluded that membrane systems in combination with appropriate pretreatment technologies can provide cost-effective recovery of low-TDS flowback water for either beneficial reuse or safe surface discharge.
The project has been completed. The final report is available below under "Additional Information".
$195,211 (20% of total)
Final Project Report [PDF-3.74MB]