Impact of Reservoir Reactions on Thermodynamic Scale Predictions

Gomes, Roberto; Mackay, Eric James; Deucher, Ricardo H.; Bezerra, Maria Carmen Moreira; Rosário, F.F.; Jordan, Myles Martin

doi:10.2118/155255-ms

Cited by 22 publications

(8 citation statements)

References 11 publications

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“…1 shows that there is a progressive decline in [Ba] (barium concentration) at low IWF (0%~50%), then [Ba] can be observed to remain very low in the produced brine from 60% IWF and above. As a whole, this kind of Ba trend is similar to some typical barium behaviours which have been frequently observed in other seawater flooded North Sea sandstone reservoirs (Paulo et al, 2001;Mackay, E.J., 2006;Houston et al, 2006;Gomes et al, 2012). However, in the Miller field, the depletion in Ba at all seawater fractions is significantly lower than observed previous in other fields.…”

Section: Analysing and Modelling Of Geochemical Datasupporting

confidence: 87%

“…However, the role of the reservoir was totally neglected in all of thermodynamic modelling work which is based on the fundamental assumption that the potential scale precipitation will be due to pure mixing of formation and injected water in the production well. However, it has been reported in some recent publications that both of brine mixing and geochemical reactions take place within the reservoir and the chemical composition of produced water would then be altered by them before arriving at producers (Paulo et al, 2001;McCartney et al, 2005;Houston et al, 2006;Mackay et al, 2006;Gomes et al, 2012;Fu et al, 2012). This paper reveals some fluid/fluid and fluid/rock interactions occurring in the reservoir through combining produced water chemical compositional data with geochemical and reservoir simulation model.…”

Section: Introductionmentioning

confidence: 82%

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Comparison of Streamline Reservoir Simulation of Brine Flow, Mixing and Barium Sulphate Induced Formation Damage with Observed Produced Water Chemical Data to Aid Scale Management

Hu¹,

Mackay²,

Vazquez³

et al. 2015

All Days

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In waterflooded reservoirs under active scale management produced water samples are routinely collected and analysed, yielding information on the evolving variations in chemical composition. These produced water chemical compositional data contain clues as to the fluid/fluid and fluid/rock interactions occurring in the subsurface, and are used to inform scale management programmes designed to minimise damage and enable improved recovery.In this interdisciplinary paper, the analyses of produced water compositional data from the Miller Field are presented and a 1D reactive transport model is developed to study possible geochemical reactions taking place within the reservoir through matching model results with observed produced water data. However, in the 1D reactive transport model, only one flow path was simulated; this does not fully represent the fluid flow and mixing behaviour in the reservoir.Therefore, this paper also presents a fully 3D reservoir simulation study for the Miller Field to evaluate brine flow and mixing processes occurring in the reservoir, using an available history matched streamline reservoir simulation model integrated with produced water chemical data. Conservative natural tracers were added into the modelled injection water, and then the displacement of injection water and the behaviours of the produced water in two given production wells were further studied. In addition, the connectivity between producers and injectors was investigated based on the comparison of production behaviour calculated by the reservoir model with produced water chemical data, and an assessment of the properties of the intervening faults was also performed. Finally, a model of BaSO4 scale precipitation was included in the model, and the simulation results with and without barite precipitation were compared with produced water chemical data (observed barium and sulphate concentrations in the produced brine). In general, the modelled and observed data were found to be in good agreement, but any discrepancies were in fact found to be very informative also. The model assumes scale deposition is possible everywhere in the formation, whereas in reality the near production well zones were generally protected by scale inhibitor squeeze treatments, and thus the discrepancies between modelled and observed data could be used to diagnose the effectiveness of the chemical treatments to prevent formation damage around the production wells. Reservoir Description and Field DevelopmentThe Miller field, located in the southern part of the south Viking Graben (Blocks 16/7b and 17/8b), covers an area of 40km 2 in the central North Sea. The production of the Brae field, located to the west of the Miller field, has caused a significant reduction of reservoir pressure in the Miller field, despite their different oil water contacts. The Miller reservoir is in the Upper Jurassic Brae Formation turbidite sands, similar to the Brae Formation reservoirs in South and Central Brae. It is sealed by the Upper Jurassic Kimmeridge Clay Formation,...

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Section: Analysing and Modelling Of Geochemical Datasupporting

confidence: 87%

Section: Introductionmentioning

confidence: 82%

Comparison of Streamline Reservoir Simulation of Brine Flow, Mixing and Barium Sulphate Induced Formation Damage with Observed Produced Water Chemical Data to Aid Scale Management

Hu¹,

Mackay²,

Vazquez³

et al. 2015

All Days

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“…Evaluation of scaling risk is generally carried out using thermodynamic prediction models (Gomes, 2012). These models are accurate in terms of predicting the type of deposits which may occur, the degree of supersaturation and the amount of scale which may deposit.…”

Section: Scaling Potential Calculations: Thermodynamic Modelmentioning

confidence: 99%

Modelling of CO2 and Seawater Injection in Carbonate Reservoirs to Evaluate Inorganic Scaling Risk

Mackay¹,

Souza²

2014

Day 1 Wed, May 14, 2014

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Evaluation of the scaling potential during field appraisal or initial development allows for a better estimation of project costs and reduces uncertainties (e.g. desulphation or scale inhibitor injection, frequency of well workover operations, etc.). When CO 2 -WAG is injected into a carbonate reservoir, several interactions between the injected fluid, the formation water and the carbonate rock may occur. These interactions may also modify the scaling potential of the produced water. Nevertheless, the prediction of these changes is challenging because it requires complex thermodynamic and kinetic modelling.The present study outlines a methodology where the geochemical modelling of CO 2 -WAG injection is used in predicting the scaling potential in carbonate reservoirs. For this, a geochemical simulation was developed, and several cases with different injection strategies were applied to obtain the produced water compositions as a function of time, and to calculate the scaling potential. The recovery method which is least susceptible to inorganic scale deposition in the studied field can be identified. The methodology was applied to data from two Brazilian carbonate fields with different petrophysical and compositional characteristics.When compared to the standard thermodynamic modelling used to calculate scaling risk, this approach takes account of the impact of the several chemical reactions that occur in situ in the reservoir, and addresses the tendency to overestimate scaling risk when reservoir reactions are not accounted for. A fully quantitative evaluation is not developed in this study since several simplifications were assumed, and many uncertainties exist in the geochemical modelling input parameters (e.g. constants related to reaction kinetics and equilibria). However, the proposed methodology provides a powerful tool for informing project decisions and field injection design. In this study, for example, CO 2 -WAG injection was found to reduce the risk of precipitation of various scales compared to seawater or Low Sulphate Water (LSW) injection.

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“…In order to choose the appropriated economical technology, scaling potential during the field life time must be well-known. So, it was considered a very careful analysis of the scale tendency to determine which scale control technique should be used since workover operations can represent high operational costs (20 ) .…”

Section: Campos Basin Giant Field -Scale Management In Turbidities Rementioning

confidence: 99%

Scale Management in Deep and Ultradeep Water Fields

2013

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Carbonate and sulfate scales formed on oilfields under natural depletion or water injection support, can occur on a number of critical points from the reservoir to topside facilities impacting on well productivity. Scale control has become a challenging task as oil industry tends to go for deeper water with complex completion wells which may produce from harsh environment conditions (HP, HT). Scale management has become a power tool to assure that oil loss due to precipitation along oil production process be avoided and costs associated to its prevention and remediation treatments be minimized. The most important factor for the success of this approach is that flow assurance strategies are considered in the field planning. Scaling risk analysis should be carried out, assessing scale tendency and intervention difficulties associated with the well design and field features. These issues are addressed in the exploration phase of the field, determining, based on risk analysis and economic evaluation criteria, the appropriate technology to be adopted. In the production phase, production data, down hole pressure measurements as well as chemical monitoring of produced water are essential for diagnosing whether any scale is being formed and to review the decisions made if necessary. In order to demonstrate the suitability of this approach, cases regarding a siliciclastic turbidite and a carbonate reservoirs in the deepwater and ultra-deepwater fields will be discussed showing different scale management strategies, such as, scale modeling by thermodynamic calculations, scale control by using downhole scale inhibitor injection, scale inhibitor squeeze treatment, scale dissolver treatment, sulfate removal unity, and downhole surveillance instrumentation (PDG, TPT).

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Impact of Reservoir Reactions on Thermodynamic Scale Predictions

Cited by 22 publications

References 11 publications

Comparison of Streamline Reservoir Simulation of Brine Flow, Mixing and Barium Sulphate Induced Formation Damage with Observed Produced Water Chemical Data to Aid Scale Management

Comparison of Streamline Reservoir Simulation of Brine Flow, Mixing and Barium Sulphate Induced Formation Damage with Observed Produced Water Chemical Data to Aid Scale Management

Modelling of CO2 and Seawater Injection in Carbonate Reservoirs to Evaluate Inorganic Scaling Risk

Scale Management in Deep and Ultradeep Water Fields

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