Produced-Water Salinity Data Optimizes Net Present Value
Authors: Carpenter Chris 
Published: January 2023

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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 200941, “Optimizing Oilfield Net Present Value With Produced-Water Salinities and Tracers,” by Babalola Daramola, SPE, Propellio. The paper has not been peer reviewed.

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The complete paper presents the value-adding applications of produced-water salinity data in three fields (B, C, and D) offshore Nigeria. The author presents case studies in which produced-water salinity data were used to transform the performance of oil-producing fields with platform well developments. Produced-water salinity data were used to improve Field B’s reservoir simulation history match, generate infill drilling targets, and reinstate Field C’s oil production.

Water-Salinity Evaluation Work Flow
The authors recommend the following work flow for collecting and evaluating produced-water salinity data:
1. Ensure that the oil-production asset has a production-test pipeline and a test separator
2. Divert the production well to the test separator and collect water samples at least once a month
3. Minimize contamination between water samples from different wells
4. Measure dissolved ions in each water sample
5. Estimate water salinity by summing up dissolved solids in milligrams per liter or parts per million
6. Convert water-salinity data units to parts per thousand
7. Create a water-salinity plot showing water-production rates (STB/D and water salinity).
8. Add the 100% formation water line to the water-salinity plot
9. Add the 100% seawater line to the water-salinity plot
10. Evaluate the water-salinity trend and differentiate formation water and injected seawater
11. Identify wells with barium sulfate (BaSO4) scaling potential
12. Recommend scale-remediation measures
13. Recommend remediation measures to remove scale
14. Use water-salinity data to track injected-seawater arrival times at production wells

Field B Case Study: History Match and Waterflood Transformation
Field B is a sandstone reservoir with undersaturated oil, four production wells (BP1, BP2, BP3, and BP4), and two water-injection wells (BW1 and BW2).
Well BP1 achieved first oil production in June 1981; water breakthrough occurred in December 1983. A sliding-sleeve water-shutoff workover was executed in 1987. Well BP2 achieved first oil production in February 1984; water breakthrough occurred in August 1986. Well BP3 achieved first oil production in July 1984; water breakthrough occurred in March 1986. Although the field had two water injectors, the production-well liquid rates declined over the production period.
A reservoir simulation model was constructed to evaluate the field’s performance and generate infill drilling opportunities. The asset team struggled to history match the water cuts in Wells BP1, BP2, and BP3 and were advised to deduce the water source in the wells and use this information to tune the reservoir simulation model.
Well BP1’s produced water was mainly formation water between 1983 and 1993; injected seawater was not seen at this well. This, along with declining liquid rates, suggest that Well BP1 received little or no water injection support from Well BW1. This is most likely the result of the 2-km distance between Wells BW1 and BP1.
Well BP2’s produced water was mainly formation water between 1984 and 1989; injected seawater was not seen at this well. This, along with declining liquid rates, suggest that Well BP2 received little or no water injection support from Well BW1, most likely the result of the 3-km distance and the partially sealing fault between Wells BW1 and BP2.