Bolivian Success: How Repsol Remediated Scale in a Sub-Andean Well
The operator developed a solution that has kept the well at stable production for over a year after treatment.
Repsol faced scale issues at its W8 well in the W field in Sub-Andean southern Bolivia. After the operator intervened to resolve scale issues at this well, its return to productivity was short-lived. The operator ultimately used a comprehensive solution that resulted in stable production for more than a year. Seen here are downhole video camera images of the Well W8 sliding side door (a) before organic acid pickling, and (b) after organic acid pickling.
Source: SPE 227964.
Scale choked gas output for the first time in a Sub-Andean, south Bolivian well after 15 years of production because of water incompatibility between completed zones, prompting several interventions.
A couple of organic acid pickling jobs dissolved the scale and brought the well temporarily back online, but they didn’t provide a long-term solution. An assessment of the composition and origin of the scale led the well’s production team to identify a remediation plan that ultimately returned the well to production and increased the time between cleanup interventions from less than 3 months to over a year.
Alejandro Guzmán, senior reservoir engineer at Repsol.
Source: JPT.
Alejandro Guzmán, senior reservoir engineer at Repsol, said while presenting SPE 227964 at SPE’s Annual Technical Conference and Exhibition (ATCE) in October that the solution for the well’s scale problems involved tubing acid pickling, zonal isolation, near-wellbore acid, and scale inhibitor. These efforts enabled the team to bring production levels from 19 MMcf/D up to 75 MMcf/D with prolonged stability of more than a year, he said.
Well W8, located in the W field in the southern Sub-Andean basin, produces from quartzite sandstone reservoir rock with 4% porosity. The well had been high-cost but also had high potential, he said. With a total depth of about 6,000 m and a maximum deviation of 27°, it had three gas-producing zones, of which the upper and middle zones were previously known, while the lower zone was a new encounter. While the lower zone was isolated, well testing revealed crossflow from the lower zone to the upper zone, which was also being produced by nearby wells.
Well W8 suffered an abrupt flow-rate decrease, from 70 MMcf/D to 30 MMcf/D less than 3 months after being put online. Guzmán said the team initially ascribed the decrease in wellhead pressure to a mechanical problem. A restriction at depth was found to be severe scale for the first time in the field’s history, confirmed by wireline video camera (Fig. 1).
Fig. 1—The sequence of events to determine scale in well W8 tubing was (a) crossflow from lower to upper zone, (b) declining performance of gas rate (MMcf/D) and wellhead pressure (WHP), (c) identification of passage restriction with slickline gauge cutter, and (d) confirmation of scale using wireline video camera.
Source: SPE 227964.
Analysis in an in-situ lab of a scale sample from Well W8 prompted the production team to use an organic acid pickling blend that was effective in the lab and at scale. Post-tubing treatment, the well went back online, but soon production dropped again. Another intervention followed, but with similar results (Fig. 2).
Both jobs “resulted in scale dissolution and immediate delivery of recovered production, but production stability lasted less than 3 months,” Guzmán said.
Fig. 2—Well W8 gas-rate (MMcf/D) and wellhead-pressure (WHP) performance.
Source: SPE 227964.
Needing a long-term solution for the well, the production team turned to a multistep workflow to analyze the fluids and scale, test the scale solubility in response to acid treatment, analyze the system fluids compatibility, analyze rock fluids, and create an integrated model of the scale.
The water analysis showed the upper-zone water was influenced by crossflow water from the lower zone, with produced water from both zones being very similar. Scale formation from this water was tested in the lab, with precipitates forming from the third day in samples at 80°F and 200°F, with more severe scale at the higher temperature.
Mineralogy analysis indicated the sample was exclusively calcite precipitate. Scale analysis revealed that within 1 hour of exposure to an organic acid composed of 13% acetic acid and 9% formic acid, 78% of the sample had dissolved, and 98% had dissolved within 4 hours of contact.
A compatibility analysis of systems fluids—condensate and water produced from the reservoir—with organic acid and inhibitors for clay, corrosion, and scale followed. No emulsions or precipitates between reservoir and treatment fluids were observed after 48 hours of contact at 200°F, according to the authors.
The team tested the addition of a polyacrylate-based scale inhibitor at different concentrations and found it could be used effectively to prevent scaling without needing further additives.
The rock-fluids compatibility analysis indicated the feasibility of treating with acid near the wellbore rather than being restricted to applying acid pickling to the tubing, which the authors said ultimately provided a deeper cleaning effect.
The team also determined the origin of the scale. They modeled the system with commercially available scale-analysis software, which allowed them to define operating conditions, zones open to production, and optimum gas rate, according to the paper. They found that pressure decrease and flow-area changes, combined with increases in temperature, pH, and calcium and carbonate concentrations, contributed to scale forming. Decreased pressure at the production sliding sleeves led to scale formation, and the most likely location for scale buildup is the production mixing point of the upper and lower zones. Water incompatibility increased the tendency for scale formation.
The production team got the green light to carry out an intervention informed by the multistep workflow, Guzmán said.
The intervention soaked the tubing, as well as the annulus and upper reservoir face, with acid for 7 hours, and well testing verified production at Well W8. Electric plugs were also installed to isolate the intermediate zone and avoid water incompatibility from causing scale to form in the future. The scale inhibitor was pumped and allowed to soak for 5 hours, followed by another production test before the well was tied back into the production-gathering system.
Production immediately recovered from 19 MMcf/D to 75 MMcf/D before settling at a sustained level of 66 MMcf/D, he said (Fig 3).
Fig. 3—Well W8 gas-rate (MMcf/D) and wellhead-pressure (WHP) history.
Source: SPE 227964.
The production “was different from the past” in that the application of the scale inhibitor allowed the well to maintain production at 66 MMcf/D for more than a year, Guzmán said.
He attributed the success of this intervention to the comprehensive solution designed to address water incompatibility, the existing flow restriction, and the prevention of future scale.
“The well is behaving better than before,” he said.
Further, the authors noted that the methodology has been applied across the wider W field and has identified candidates for future chemical treatment.
