Water is an essential component for oil and natural gas production during the drilling and hydraulic fracturing processes. Water from fracturing operations is exposed to millions of naturally occurring microbial contaminants that can cause souring, corrosion, emulsion problems, and plugging in pipelines, injection wells, pumps and filters.
Most of this water comes from surface water sources such as area lakes, ponds, rivers and municipal supplies. The industry's thirst for water has revealed challenges in sourcing a sufficient amount to sustain the level of completion activities. Millions of barrels of water per day are being processed from oilfields for treatment and recycling projects.
Because of decreased oil prices, many operators' budgets are being revisited and scaled back during 2015. However, some water solutions and services provide several cost-effective solutions for operators' water management needs.
A More Complete System
Two systems were recently combined to provide more complete surface water treatment before downhole fracturing. The first system is a chlorine-dioxide biocide, which was combined with a proprietary scale inhibitor to create the new system.
Chlorine dioxide (ClO2) is the most effective biocide that reacts within seconds and is recognized by the U.S. Environmental Protection Agency as environmentally friendly. It is less corrosive than chlorine and superior for the control of Legionella bacteria outside the oilfield.
Two-precursor ClO2 systems react less with organic matter in water, minimizing trihalomethanes. This two-precursor system is one of the safest ways to generate chlorine dioxide on-site. Available in 30-foot mobile units, this system integrates with the hydraulic fracturing crew, allows for a small on-site footprint and moves seamlessly from job to job.
The system also includes the following benefits:
- It uses less harmful chemicals and is more cost-effective than traditional solutions and other ClO2 systems.
- A stationary unit can treat saltwater at disposal facilities and reserve pits.
- The system has two ClO2 generators for redundancy and maximum generation of ClO2.
- Monthly reports are reviewed with users to validate results (KPI).
The second system is a scale inhibitor. This system prevents carbonates, sulfates and other matter from forming larger deposits during the blending process of fracturing. If a scale inhibitor is not used, deposits will clog pumps, pipelines and other equipment, which will affect and delay operations.
Scale inhibiting technologies also help eliminate the buildup of calcium carbonate and other matter that occurs along production tubing and equipment.
This buildup is caused by the pressure and temperature changes as oil is produced. This second system works to inhibit the crystallization of mineral scales. If left untreated, these crystals will agglomerate.
This system's benefits include the following:
- Superior scale treatment
- Superior tagged polymer scale inhibitor for maximum protection of the formation and wellbore equipment
- Rapid residual analysis for flowback monitoring
- High thermal stability capable of withstanding temperatures up to 375 F
- Trailer-mounted setup for mobility
- Ease of deployment and management through a single point of contact
By combining the two solutions, operators receive further savings by making use of a single operation crew for multiple services. The combination is unique to the industry and provides a one-stop shop for operators' bacteria and scaling issues. The following case study demonstrates the system's success with an operator who combined the two solutions and was able to reduce bacteria and scale while lowering costs and increasing efficiencies in the company's operations.
Case Study: New Mexico
A Fort Worth-based independent oil and gas exploration and production company with operations in New Mexico and the Permian Basin areas of the U.S. was experiencing high bacteria counts in its water. In New Mexico, bacteria were traveling downhole at the injection site, causing corrosion to the source well.
The combined system had provided water management solutions to major operators in the New Mexico-Permian region since 2012. After reviewing its processes, the operator realized that the combined solution was the best and most cost-effective choice to eliminate bacteria, hydrogen sulfide (H2S) and scale-related issues.
After evaluating the operator's situation, the ClO2 solution was chosen for on-site ClO2 production to eliminate bacteria in the source water, stop H2S production and prevent plugging of the formation/equipment because of iron sulfide (FeS) and biofilm. In addition to the ClO2 system, the operator decided to use the scale inhibitor solution, benefiting from a single crew and saving money by using the combined solution. Table 1 shows the combined system benefits.
In Well 1, treated between Aug. 3 and Aug. 8, 2014, the source water analysis revealed significant bacteria concentration. The concentration of acid-producing bacteria (APB) and sulfate-reducing bacteria (SRB) is measured in bottle turns, which is a recognized American Petroleum Institute (API) method (API RP 38) to determine bacteria counts in the water.
Based on the data in Table 3, the pretreated water was "turning" five bottles of APB and one of SRB respectively at 15 and 30 days after incubation. However, after treatment with ClO2 at the tank level, bacteria was not detected in the water after the treated point or at the tank. ClO2 acts within seconds after injection within the main water transfer line. In a recycling project, flowback water will need to be treated again to ensure that only bacteria-free water is reintroduced into the wellbore.
The scale prevention treatment in New Mexico used nucleation and crystal modification to prevent scaling and can be used at temperatures up to 375 F downhole. Given the scaling tendencies for this site's water, specifically the calcite potential, a minimum of 8 parts per million (ppm) residual of the phosphonate tag was required. This residual is measured at 30 days after production starts to ensure a longer term of treatment efficacy and could be prolonged as long as the operator required. In this case, after 30 days of continuous treatment, the residual was 16.95 parts per million.
SRB and ACB are especially vulnerable to ClO2 oxidation.
ClO2 attacks the fundamental physiology of bacteria, prohibiting both anaerobic and aerobic bacteria from developing resistance, and eliminates the need to alternate biocide treatments.
ClO2 is not only an effective biocide. Its oxidizing properties will destroy H2S and FeS contaminants in the system, and is ideal for impounded produce water treatment.
Below are some objectives of the treatment and observations from the New Mexico wells. The results from Well 1 are summarized in Figures 1, 2 and 3.
The goal was to maintain consistent ClO2 residual in the tank to ensure sterilization of the water.
The systems' analyzer automatically adjusted the delivery of ClO2 on demand to maintain the target residual, which helps with on-site operations and safety.
Fluctuations were observed in the delivery rate of ClO2, and this had a direct correlation with the bacteria concentrations observed in the water. The system reacted in real time.
In Stage 1, the water was treated higher at the set point to sterilize the tanks. In most cases, a large delta shown between the analyzer set point and the residuals measured indicates that the inlet water was temporarily dirtier than the previous stages.
The system monitors every 15 minutes at all points of measure to ensure a cost-effective use of ClO2.
ClO2 has no significant impact on the pH of the fracturing fluid (see Figure 3). This is important because a high or low pH may disrupt the efficacy of the fluid. ClO2 has a limited to no effect on the pH of the fluid, is pH-tolerant and kills organisms from pH 2 to pH 10.