The Biggest Elephant in the Room in Unconventional Scale Programs: Iron

Spicka, Kevin; Bhandari, Manojkumar; Bhandari, Narayan; Colmenares, Laura; Littlehales, Ian; Seufferlein, Ben

doi:10.2118/200694-ms

Day 2 Thu, June 25, 2020 2020

DOI: 10.2118/200694-ms

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The Biggest Elephant in the Room in Unconventional Scale Programs: Iron

Kevin Spicka¹,

Manojkumar Bhandari²,

Narayan Bhandari³

et al.

Abstract: The development of unconventional basins across North America for the past decade initially caused some in the industry to wonder if challenges found in unconventional basins would require new chemistries and technologies. As the basins have been produced and water chemistries evaluated and treated, it has become clear that established scale inhibitor chemistries and methodologies are suitable to treat unconventional scaling scenarios. However, the number of applicable chemistries can be limited as some of the… Show more

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Cited by 3 publications

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Theories and Work Towards Understanding a Mysterious Case of Severe Bakken Brine Incompatibility

Spicka¹,

Eagle²,

Longie

et al. 2021

SPE International Conference on Oilfield Chemistry

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The Bakken formation is well known for producing brine very high in total dissolved solids (TDS). Halite, calcium carbonate, and barium sulfate scales all can pose substantial production challenges. Trademarks of Bakken produced brine include elevated concentrations of sodium (>90,000 mg/L), chloride (>200,000 mg/L), and calcium (>30,000 mg/L), contrasted against low concentration of bicarbonate (50-500 mg/L). In the past 3 years, operators have experienced unexpected instances of severe calcium carbonate scale on surface where produced fluids from the production tubing commingled with the gas produced up the casing. Initially treated as one-off scale deposits despite the application of scale inhibitor, acid remediation jobs or surface line replacement were typical solutions. As time has passed, this issue has become more and more prevalent across the Bakken. Investigation of this surface issue discovered a most unexpected culprit: a low TDS, high alkalinity brine (up to 92,000 mg/L alkalinity measured to date) produced up the casing with the gas. When mixing with the high calcium brine typically produced in the Bakken, the resulting incompatibility posed remarkable scale control challenges. The uniqueness of this challenge required thorough analytical work to confirm the species and concentrations of the dissolved ions in the brine produced with the gas. Scale control products were tested to evaluate their abilities and limitations regarding adequate control of this massive incompatibility. The theory that corrosion contributed to this situation has been supported by a unique modelling approach. Once corrosion was identified as the likely source of the high alkalinity brine, corrosion programs were instituted to help address the surface scaling. This paper highlights the evaluations conducted to fully grasp the severity of the incompatibility, the theories put forth to date, work conducted to try to replicate the phenomena in the lab and in models, and chemical programs used in the field to address corrosion and scale. While not known to exist in other oilfield basins, conventional or unconventional, this discovery may have implications for the broader industry if similar situations occur. The possible explanations for why this may be happening may have implications for scale control, asset integrity, and potentially even the methods by which wells are produced.

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Theories and Work Towards Understanding a Mysterious Case of Severe Bakken Brine Incompatibility

Spicka¹,

Eagle²,

Longie

et al. 2021

SPE International Conference on Oilfield Chemistry

View full text Add to dashboard Cite

show abstract

Prevention of Inorganic Scale in ESPs - A Holistic Review of Scale Inhibitor Deployment Options

Johnston¹,

Jordan²

2022

Day 1 Wed, May 25, 2022

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Electrical Submersible Pump (ESP) failures have a range of root causes from reservoir solids/ sand, fracture proppant and asphaltenes within the intake assembly of the pumps to deposition of different types of inorganic scale on the motor. The formation of such scale deposits is not unusual, and the mechanism of formation is well understood but the fact that scale deposition and associated pump failures can be observed to occur at water cuts of <1% is less well understood. Treatments with scale inhibitor via continual injection are not always successful at such low water cuts and failure to inhibit scale can also be a result of poor understanding of the mixing point of inhibitor and brine vs the location of onset of scale formation. The deployment of conventional scale squeeze treatments can be associated with significant oil production losses which are commonly attributed to the treatment of low water cut wells with aqueous based scale inhibitors, and operational issues may be caused by the requirement to pull the pump if a bypass valve is not present. This paper outlines the development of an effective treatment strategy for production wells that suffered significant performance impairment at water cuts below 5% due to carbonate scale deposited within the ESPs. These wells were treated with a mutual solvent and an oil soluble scale inhibitor squeeze treatment. Field results agreed with the laboratory qualification studies showing that the wells treated did not suffer any reduction in oil production rate and the ESPs were effectively protected from carbonate scale deposition. This work was extended, and applications carried out within offshore fields in the GOM and West Africa where scale inhibitor was applied in fracture fluids programs used for frac pack operations to provide scale inhibition but eliminating the need for an initial squeeze at low water cut. The development of scale inhibitor compatible with the fracture fluids eliminated the need for expensive well intervention until the water cut of the wells exceeded 10% whereby the continual downhole injection system was able to protect the ESPs. The paper highlights the need to understand the implication of the location of the ESP/motor within the completion in each well to allow assessment of the best scale inhibitor deployment strategy in each case. The selection of treatment strategy is discussed, along with the laboratory qualification studies required to select appropriate inhibitors. Case history data demonstrating successful deployment in the field for continual injection, solid inhibitors and squeeze application are presented, along with analysis of the risk factors to be considered when reviewing the scale formation potential over the lifecycle of a well in new field developments.

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Data Driven Total Systems Analysis Leads to Successful Treatment of Severe Calcium Carbonate Scale in the Delaware Basin Avalon Formation

Hudson,

Spicka,

Potter

et al. 2024

Day 2 Thu, June 06, 2024

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There has been a recent shift in the Permian across unconventional frac targets in the Delaware Basin stacked play. Operators are now targeting shallower zones, such as the Avalon formation. When comparing key scale risk drivers, such as brine compositions and mol% CO2 of the Avalon formation to more traditional targets such as the Wolfcamp and 2nd & 3rd Bone Springs, not only does the Avalon present its own unique scaling challenge, but the commingling of these formations can present a much greater scale control challenge. Previous work highlighted the Avalon formation's high natural potential for carbonate scale precipitation, which aligns with field history presented here. These unique challenges will play a part in the next wave of formation-based proactive chemical treatment strategies across upstream, midstream and water disposal systems. Here we present a case of severe carbonate surface scaling from Avalon formation brines. The operator was experiencing calcium carbonate scaling on flowlines, water legs of separators, and equalizing lines between water tanks every 3 to 4 months. The operator had to choose between using heater treaters in winter to sell oil or scaling off the heaters. Incumbent service companies had successfully controlled downhole scale but could not control the surface scale issues. A total systems analysis including field analysis, scale modeling, 21 produced fluid chemical compatibility experiments run across 11 different scale inhibitors, minimum effective dosage (MED) identification through 119 NACE static/synthetic brine and Dynamic Scale Loop (DSL) testing was performed to identify a solution. The solution highlighted in this paper resulted in zero facility scale-offs (26-month treatment period to date of publication), use of heater treaters in winter to sell oil, and operational efficiency gains in reduced manpower for cleanouts. Additionally, the ability to now commingle high-risk brines at central tank batteries allowed for the decommission of small satellite facilities previously used to isolate the highest scale risk brines. The Avalon is not a new target but is projected to become more common in the future. The recent shift has implications to change how, where, and why we treat for carbonate scale in the Delaware Basin.

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The Biggest Elephant in the Room in Unconventional Scale Programs: Iron

Cited by 3 publications

References 5 publications

Theories and Work Towards Understanding a Mysterious Case of Severe Bakken Brine Incompatibility

Theories and Work Towards Understanding a Mysterious Case of Severe Bakken Brine Incompatibility

Prevention of Inorganic Scale in ESPs - A Holistic Review of Scale Inhibitor Deployment Options

Data Driven Total Systems Analysis Leads to Successful Treatment of Severe Calcium Carbonate Scale in the Delaware Basin Avalon Formation

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