Abstract

Acid stimulation is a frequently used technology to enhance the production rate of hydrocarbons from a reservoir. Severe iron carbonate deposition has been observed recently during acid stimulation in sweet carbonate gas wells, especially for high-temperature high-pressure (HTHP) wells. It offsets the performance of acid stimulation, causes severe flow assurance issues, such as formation damage and tubing blockage.

To study iron carbonate formation during acid stimulation, corrosion coupon tests were conducted to collect data of the corrosion rate and iron released from tubing during the acid injection stage of acidizing treatment. To simulate iron carbonate depositing in the near-wellbore region, scale prediction software (ScaleSoftPitzer) was applied to simulate the scaling tendency and potential mass deposition. This allows an insight into the iron carbonate precipitation.

Results show iron carbonate deposition during acid stimulation is a corrosion induced scale issue. A high concentration of iron can release from tubular due to severe corrosion during acid injection, especially for the high-temperature reservoir. Minor iron carbonate could deposit at the initial stage of acid injection due to low the pH of spent acid. However, sever iron carbonate can precipitate when spent acid with pH ~3.8 mixes with formation water. A large amount of iron carbonate could deposit in the near-wellbore region or tubing, which potentially causes severe flow assurance issues and offsets the performance of acid stimulation.

This paper presents a fundamental study to understand the mechanisms of iron carbonate deposition during acid stimulation in sweet carbonate reservoirs. It will benefit defining a proper strategy to control iron carbonate deposition in downhole tubing and near-wellbore matrix. Appropriate mitigation strategies are recommended.

Introduction

The formation of mineral scale is a flow assurance problem during oil and gas production. Scale deposition on the surface facilities, downhole tubing and near wellbore region in the reservoirs may create many problems including pipe or valve blockage, unscheduled equipment shutdown, and even more importantly production reduction.1-5 Over the past few decades, great efforts have been made to understand the conventional oilfield scale formation and inhibition, such as CaCO3, BaSO4 and CaSO4. Compared to these conventional mineral scale deposits, iron carbonate, an exotic scale, has received fewer attentions.

Keywords:
corrosion inhibition, pipeline corrosion, hydrate remediation, paraffin remediation, drilling fluid selection and formulation, hpht, oilfield chemistry, drilling fluid property, flowline corrosion, materials and corrosion
Subjects:
Drilling Fluids and Materials, Production Chemistry, Metallurgy and Biology, Pipelines, Flowlines and Risers, Unconventional and Complex Reservoirs, Drilling fluid selection and formulation (chemistry, properties), Acidizing, Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene, Materials and corrosion, HP/HT reservoirs, Well Integrity
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2021. Association for Materials Protection and Performance (AMPP)
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