Enhanced recovery

Case Study: Novel Scale Inhibitor Extends Treatment Lifetimes in Permian EOR

The application of an extended-release scale-inhibitor in approximately 70 vertical conventional wells in the Permian Basin has shown approximately three times better performance compared to the incumbent chemical.

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A new extended-release (ER) scale-inhibitor technology showing significantly increased lifetimes has been applied in the Permian Basin. Tomson Technologies and Group 2 Technologies, in partnership with Occidental Petroleum (Oxy), implemented a scale-squeeze program for this carrier system. It allows for fewer squeeze treatments, which results in lower chemical usage, decreased plugging risk, and reduced environmental impact.

Squeeze programs are an effective field treatment strategy to prevent scale formation in wells for extended periods of time. However, in some cases, squeeze lifetimes can be short, leading to frequent re-squeezing and production decreases, lowering overall economic recoveries.

The ER phosphonate-based chemistry (SI1313) was used in selected wells where incumbent (previous chemical provider) treatment lifetimes were shorter than expected. The incumbent squeeze volumes and additives were used, and the scale-inhibitor (SI) chemistry was replaced with SI1313 to obtain directly comparable results.

The wells selected are vertical wells, with predominantly carbonate mineralogy and 14–18% porosity and 9–16 mD permeability. Bottomhole temperature is 105°F (40°C). These wells are under continuous CO2 flooding operations, and the scales of interest are calcium carbonate and calcium sulfate predominantly. The selected wells were targeted to have a good squeeze history for comparison and stable water production.

Pre-Job Validation Work

Coreflood laboratory experiments were performed to simulate the adsorption and desorption under these specific Oxy Permian conditions. The coreflood showed over 10,000 pore volume (PV) of flow with inhibitor concentration remaining above the minimum effective concentration (MEC) during the entire run. Once greater than two times incumbent performance was reached, the coreflood was stopped, although the return concentration was still above MEC. For reference, corefloods with incumbent phosphonate chemistry under the same conditions usually drop below MEC around approximately 3,000–5,000 PVs.

The adsorption of SI1313 to core material was measured during the coreflood experiment and the results show 12.5 mg of inhibitor adsorbed per gram of core material. As a comparison, a typical incumbent phosphonate scale inhibitor adsorbs 1–2 mg of inhibitor per gram of core material. This increase in adsorption is considered a large improvement over traditional chemistry. The carrier platform’s superior adsorption, when combined with controlled desorption, is the basis for extending the lifetimes of scale-inhibitor treatments.

The corefloods results validate the ER characteristics expected from SI1313 and allowed for field squeezes to be conducted.

Field Application

Group 2 Technologies provided SI1313 to be squeezed for Oxy in January 2020, into five vertical conventional wells. The selected wells are in one area where CO2 flooding is in place and there is risk of calcium carbonate (CaCO3) and calcium sulfate (CaSO4) scaling. These wells have had many scale squeezes performed on them, yielding an excellent data set to compare against. The goal of this trial was to show significant lifetime extension compared to previous incumbent squeeze lifetimes.

The squeeze recipe for the selected wells was an exact copy of the prior squeezes, fully matching except for the scale inhibitor which was replaced with SI1313. Residuals were measured via phosphorous on a well-calibrated ICP (inductively coupled plasma for spectrometry), the same as the incumbent chemistry.

The following squeeze recipe was used; the product names, exact concentration, and stage volume have been removed due to confidentiality.

  1. Preflush: Fresh water+mutual solvent+SI1313+biocide
  2. Main Stage: Fresh water+SI1313+biocide
  3. Overflush: Fresh water+biocide
  4. Shut In: 18 hours

The treatment volumes were targeted to achieve a 5-ft radial penetration. The treatment pressure was monitored during the squeeze, and no pressure increase was observed in any squeeze performed. Well tests before and after treatment show that SI1313 did not cause damage to production. Following the squeeze with SI1313, oil rate regained to pre-squeeze levels and pressure remained stable.

Post-Squeeze Flowback and Residual Analysis

Samples for residual analysis were collected and analyzed by the service provider for the SI1313 squeezed wells. Residual analysis to date is shown in Fig. 1 for one example well.

Residual inhibitor concentration graph
Fig. 1—Average squeeze treatment lifetime observed with incumbent scale inhibitor and SI1313 in three fields in the Permian Basin (approximately 70 wells are represented in the data).

As shown, the average duration of the previous three squeeze treatments on this well is approximately 5 months. The ER squeeze using SI1313 has been returning above MEC for 16 months as of this writing, yielding more than approximately three times (300%) lifetime over the incumbent scale-squeeze treatment. Since the treatment is ongoing, lifetime continues to provide benefits for the operator. This well, like all others performing squeezes, has eliminated at least two additional squeezes and the associated costs of scale-inhibitor chemical, personnel, vehicles, and deferment associated thereto. The water production in this well has remained constant throughout this period and is controlled by CO2 and water-flooding operations. The release profile in Fig. 1 shows a plateau region at the tail of the curve, characteristic of the performance of the ER carrier platform, and is seen in our laboratory studies and other well squeezes.

The result from these five wells is in line with the previous field results observed in the Gulf of Mexico. Increased adsorption and ER of inhibitor resulted in an increased treatment lifetime, attributed directly to the ER scale-inhibitor technology.

Following the case study with five wells, the treatment was applied in two other Oxy fields in the same production area. A summary of the squeeze lifetime for each of the three fields where Oxy has applied SI1313 is shown in Fig. 2. There are now more than 70 wells that have been treated with SI1313 in the past year, all of which have outperformed incumbent squeezes. Oxy is continuing to apply SI1313 in this area.

incumbent scale inhibitor graph
Fig. 2—Residual inhibitor concentration in mg/L over time for Well B. Green lines represent squeeze interventions. Events before January 2020 were performed with the incumbent chemistry; the squeeze in mid-January 2020 was performed with SI1313 and is ongoing.


The application of SI1313 in conventional onshore wells has shown approximately three times better performance compared to the incumbent chemical over approximately 70 wells at the time of this writing. The product has been widely applied in vertical conventional wells in the area with great success.

This ER scale inhibitor continues to be applied in the area in other onshore and offshore wells, where the technology has been proven to work in both sandstone and carbonate reservoirs with a wide range of well conditions and compositions.

Tomson Technologies continues to apply the technology of carrier platforms to production chemicals to increase adsorption to the reservoir and control the release rate. This work will allow for future trials in other flow-assurance areas. We continue to work with our operator partners to develop other ER-enabled chemicals that significantly improve the performance of existing production chemicals, especially in those areas where squeezing currently cannot be performed or is underperforming. Multiple other applications for this technology have been identified by operators and are being developed.

For Further Reading

A previously published case study describes the results of completed field trials in the Gulf of Mexico by Shell and Tomson Technologies using nanoparticle-enabled phosphonate and polymer inhibitors that improved the treatment lifetime of scale squeezes.

A Game Changer in Scale-Squeeze Technology by Paula Guraieb, Ross Tomson, Victoria Brooks, Ji-young Lee, and Jay Weatherman.

Paula Guraieb is vice president of Tomson Technologies with over 10 years’ experience in project management for new technology development related to oil and gas production.
Anna Courville is a production engineering advisor for Occidental Petroleum with 20 years’ experience. She has managed production operations from the Gulf of Mexico shelf to deepwater and now works in west Texas. She is currently developing plans for future options for carbon-dioxide-enhanced oil recovery. She has a chemical engineering background.
Vaibhav Nikam is mechanical integrity engineer advisor at Occidental Petroleum Company (Oxy) in the Permian EOR business unit. He has 13 years’ experience in the areas of metallurgical and corrosion engineering, production chemicals, and risk-based inspection.
John Kennedy is the senior chemical treatment specialist at Occidental Petroleum (Oxy) in the Permian EOR business unit. He has more than 16 years’ experience in various disciplines of chemical prevention and remediation in primary and EOR applications.
Ross Tomson is president and founder of Tomson Technologies. Combining scientific and business backgrounds, Tomson focuses on delivering exceptional innovation that drives value across the full life cycle of energy production.
Robby Nelson, CEO, and Brad Sears, COO, Group2 Technologies.