Gas well treated with 100% reused frac fluid

In its shale-gas production operations in the eastern Marcellus Shale underlying Susquehanna County, Pennsylvania, Cabot Oil & Gas Corp. has fracture-stimulated a two-stage, 6,950-ft vertical well, using fracturing fluid consisting of 100% frac-fluid flowback. The flowback fluid was first processed using specific, fit-for-purpose water-treatment methods. Next, the fluid was engineered to meet the pumping-friction, downhole aqueous geochemically driven scaling and precipitation potential, and micro¬biological challenges presented by shale-gas reservoirs stimulated using high-rate, high-volume hydraulic fracturing technology.

Flowback fluid used for the project was taken at random from Cabot tanks. (Fig. 1) Cabot’s goal going in was to conduct the fluid reuse pilot project using 100% flowback fluid as source water to prepare carrier fluid for the job; no fresh water was mixed with the final fluid. The treatment was placed with a total of 8,300 sacks of propping agent consisting of natural 100-mesh and 40/70-mesh sands. Of this total, 300 sacks of 100-mesh sand and 8,000 sacks of 40/70-mesh white sand was placed over two intervals. Initial 30-day production from the well was among the highest within Cabot’s development area in the eastern Marcellus to date.

The solution–two major steps
Reuse of the flowback fluid without processing was not considered appropriate due to the geochemical content it had picked up from the reservoir during pumping and flowback sequences. A key to this solution involved a science-based assessment of in-situ geochemistry and formation compatibility of the waters, and levels of specific cations and anions that needed to be selectively removed.

Flowback water is stored at a Cabot location.

The flowback fluid was chemically of fair quality, with moderate iron and near-neutral pH. Dissolved constituents comprised high chlorides and hardness; sulfate levels were low. Microbiological content was moderate; divalent cations were a consideration (Table 1). Processing would feature (1) application of specific mobile water-treatment processes according to specification; and (2) engineering of a fracturing fluid that can place proppant into producing intervals while preventing negative geochemical reactions.

The processing strategy addressed the main concerns that any operator might have when reusing water: scale, iron deposition, suspended solids, microorganisms that could form in the proppant pack, and good pH and other water attributes needed to achieve adequate friction reduction (FR). Steps taken are listed:
1. Adjust the flowback to a pH that is optimum for specific divalent and metal precipitation.
2. Use a divalent cation (Ba, Sr, Ca, etc.) additive to complex soluble ions and sediment the resulting particle.
3. Remove iron by converting Fe2+ (soluble iron) to Fe3+ oxide/hydroxide (particulate iron) mechanically and chemically; use sedimentation process for removal.
4. Perform a microbiological disinfection if needed.
5. Conduct a final filtration step to remove any remaining suspended solids and dead biomass.

The treatment process was effective in removal of scale-forming, divalent cations (Table 1). Flow-loop testing showed that addition of 0.5 gal/Mgal of a patented, salt-tolerant, polymer friction reducer (Fig. 2) could assure functional performance of the friction reducer in the presence of high salinity along with residual amount of other anions and cations.

With the water treated to reduce divalent cation content (Table 2), the frac fluid could be designed for optimal performance near that of fresh water from a friction performance perspective. Based on field flowback studies from offset wells, Cabot elected to deploy the engineered fluid package containing:
• Patented salt tolerant, nano-particle friction reducer
• Patent-pending iron complexing agent
• A scale inhibitor blend fit for predicted geochemical species
• Biocide designed for mitigating observed microbial biomass

The conductivity trend shows a steady increase in total dissolved solids (TDS) with increasing flowback volume. Upward trends show that water picks up solids in proportion to contact with the shale. Sulfates, although much lower than other ions, indicate sulfate scale control is needed both in-situand when reusing water.

When put on production, the well produced gas among the highest rate of any well in the same geologic setting; however, other wells used fresh water to create the frac fluid. Flowback fluid was analyzed and considered suitable for processing and reuse at 100% concentration (no dilution with fresh water needed) in the next Cabot well (Table 3). The water will be processed as described above, and re-engineered using the four-component system (FCS). Flowback water can be engineered and reused as needed, provided proper levels of divalent cations, iron, suspended solids, and pH are maintained.

System components
Regulatory agencies, landowners, citizens concerned about environmental impact, and municipalities concerned about supplies of fresh water are drivers behind industry efforts to reuse water from which fracture fluids are prepared.

Operating companies and other well-service companies have approached the problem of renewable freshwater supply by separating, filtering, and even distilling or crystallizing produced formation waters and frac-fluid flowback waters to purify them for future use or surface discharge. The FCS enables use of frac fluid mix waters that do not require high-purity fresh water. The source waters are (1) monovalent and anion tolerant in the presence of specific ratios of divalent cations (brine up to 12% NaCl and sulfate concentrations > 6%), and (2) pH tolerant. Four subsystems that play key, synergistic roles in preparation of fracturing fluid from flowback and produced waters are described below.

Salt tolerant, nano-particle friction reducer. The friction reducer (FR) additive is a liquid-polymer FR emulsion that is brine tolerant and results in minimal formation damage within the shale matrix and micro-crack networks. It is designed especially for use in shale formations from an ionic charge perspective and is well designed for environmentally sensitive applications. The friction reducer also contains micro- to nano-particles that act to minimize leakoff and imbibition, thereby increasing fluid efficiency and minimizing fluid imbibition damage within the fracture face and shale matrix. Use of this salt-tolerant friction reducer (STFR) technology lowers pumping pressure by 50–75%, permitting a significant reduction in well-site hydraulic horsepower, and enables high rates to be achieved at the lowest possible surface treating pressures. This FR enables the reuse of fracturing flowback water and produced formation water as the base fluid in subsequent frac treatments.

Neutral pH iron control. The iron-control (IC) agent chemically complexes iron in formation fluids in the reduced-valence state to prevent precipitation and complexation of iron compounds with other mineral phases. The polymer inhibits the iron from converting to insoluble particulates that can (1) damage fracture conductivity and (2) reduce the production potential of the formation. Free iron also acts to de-activate the effectiveness of scale inhibitors. The unique characteristic of this component is the capability to provide IC at low chemical loading without the adverse side effect of reducing friction performance and system pH, a property typically found in IC agents. This additive works synergistically with a Superior Well Services Inc. (SWSI) scale-control additive in (1) preventing precipitation of difficult post-frac geochemical species such as siderite (which can form in hydraulic fractures), (2) preserving effectiveness of other scale inhibitors, and (3) enhancing performance of FR chemistry.

Blended scale control (BSC). The blended scale-control agent (BSCA) that was formulated to achieve the reuse goals simultaneously protects against three types of scale or precipitate: carbonate, sulfate, and iron-based scale depositions. Unprotected, the downhole environment can lead to formation of geochemical precipitates within the created fracture network and potential scale accumulation in perforations, piping, and surface equipment. The BSCA also contributes to enhancing friction reduction rather than negatively impacting it as many conventional scale inhibitors have been shown to do.

From left, samples are (a) untreated flowback water stored by Cabot, and (b) processed water used as source to prepare frac fluid.

Aqueous biomass control (ABC). For control of bacteria, SWSI uses an environmentally responsible, broad spectrum biocide that impedes the growth of bacteria and degrades rapidly in the surface environment. The biocide mitigates sulfate-reducing bacteria, the microorganisms that cause downhole H2S souring and equipment erosion, along with other chemosynthetic microbes such as acid-producing bacteria (APB) and iron bacteria. It also controls slime-forming bacteria.

The operation
The well was stimulated with 100-mesh and 40/70-mesh frac sand. Frac fluid was the engineered system described above. Two sets of perforations were made and the well was fracture-stimulated in two stages.

Nine samples of flowback from the well were submitted for water analysis; samples were collected over a period of 500 bbl to 4,500 bbl flowback recovery. The total load recovery was 8,000 bbl out of a total 19,000 bbl pumped. A water analysis was run on each sample; the results and trends are listed below. Table 3 presents an excerpt taken from the detailed flowback results.

Post-frac production performance
Following the hydraulic fracturing operations, and flowback period, initial production results were obtained over a period of 30 days. Based on these results, it was observed that the well fractured using 100% re-use water and associated chemical package produced among the best rate of all other wells in the same geologic setting.