Scale Inhibitor Squeeze Treatments Deployed From an FPSO in a Deepwater,
Subsea Field in the Campos Basin

Bogaert, Philip; Berredo, Marcos C.; Toschi, Celso; Jordan, Myles Martin; Frigo, Dario M.; Morgenthaler, Lee N.; Afonso, Macros

doi:10.2523/102503-ms

Cited by 7 publications

(8 citation statements)

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“…This is best illustrated by plotting barium concentration vs seawater fraction in the produced water. A typical example from the literature [14][15][16]30 is shown in Fig. 5, where it is clear that the measured barium concentrations for all wells in this field fall considerably below where they would be expected if dilution was the only factor, despite the fact that all the wells in this field had been under active scale management by squeeze treatments.…”

Section: Performance Of Squeeze Treatmentsmentioning

confidence: 86%

The Development of a Scale Management and Monitoring Program for a High-Temperature Oil Field During the Production-Decline Phase of the Life Cycle

Jordan¹,

Sørhaug²,

Marlow³

et al. 2007

Proceedings of International Symposium on Oilfield Chemistry

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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThis paper presents field results from scale squeeze treatments carried out on platform wells within a high temperature (150C) field in the Norwegian sector of the North Sea. Scale control and the resulting squeeze treatments to production wells were highlighted as the most expensive item in the production chemical budget. The development of a cost-effective squeeze and monitoring policy has been critical to reducing the operating cost of this asset as the produced water cut rose.The decision to use both aqueous and emulsified scale inhibitor for treating these high temperature production wells was arrived at after an extensive series of laboratory tests including formation damage coreflood studies and an assessment of chemical retention at this elevated temperature. The field data from these wells will be presented comparing treatment lifetimes and clean up rates between conventional treatments and the novel emulsion technologyA key factor to the success of such treatment is an understanding of chemical placement and the effectiveness of the treatment chemicals. Evaluation of residual chemical concentration or scaling ion chemistry has long been used in monitoring programs and more recently probes have been developed which increase the rate of evaluation/interpretation. All these monitoring methods prove that the chemical is present in the brine when sampled or that scale formation is not occurring at the point of brine analysis. This paper outlines the experimental methods developed to evaluate the suspended solids collected from the produced brine by environmental scanning electron microscope (ESEM) and the associated brine chemistry to evaluate the scale risk within the produced fluids. The combination of these methods has improved the integrated scale management program in terms of evaluating scale squeeze placement effectiveness, squeeze lifetime and provides the confidence t0 extend the period between scale squeeze treatments. Also, and in some cases treatments were stopped where brine analysis alone would have suggested further scale squeeze applications were required.

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Section: Performance Of Squeeze Treatmentsmentioning

confidence: 86%

The Development of a Scale Management and Monitoring Program for a High-Temperature Oil Field During the Production-Decline Phase of the Life Cycle

Jordan¹,

Sørhaug²,

Marlow³

et al. 2007

Proceedings of International Symposium on Oilfield Chemistry

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show abstract

“…This is best illustrated by plotting barium concentration vs. seawater fraction in the produced water. A typical example from the literature 4,5,11,12,15,19 is shown in Fig. 2, where it is clear that the measured barium concentrations for all wells in this field fall considerably below where they would be expected if dilution was the only factor, despite the fact that all the wells in this field had been under active scale management by squeeze treatments.…”

Section: Performance Of Squeeze Treatments and The Impact Of Ion Strimentioning

confidence: 87%

“…In production wells it is well documented that the scale risk will evolve with time 15,17,19,20 . This evolution is accounted for by two general trends -increasing water cut which means that increasing volumes of water require to be treated, and changing brine composition, which means that the MIC will vary with time.…”

Section: Implications For Scale Managementmentioning

confidence: 99%

The Optimisation of a Scale Management and Monitoring Program for During the Production-Decline Phase of the Life Cycle

Jordan

Strachan

Johnston³

et al. 2007

All Days

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“…Scale formation has been a production issue in these fields as they are supported by injection of seawater and the formation water contains up to 180 ppm of barium. 1,2 Wells with seawater breakthrough are squeezed to control sulfate and carbonate scale with a phosphate ester scale inhibitor. This treatment was designed to control scale formation within the wells and flow lines, with a supplemental scale inhibitor injection to the topside process.…”

Section: Field Description and Scale Control Strategiesmentioning

confidence: 99%

“…1,2,9,10,11 • Brine 2, ideal formation water that showed no reduction in barium. Brine 2 was evaluated at different seawater breakthrough ratios o 90:10 Formation water : Seawater o 50:50 Formation water: Seawater These conditions were selected to simulate field conditions.…”

Section: Subsea Scale Inhibitor Qualification Performance Testingmentioning

confidence: 99%

Deployment, Monitoring and Optimisation of a Scale Inhibitor and Associated Corrosion Inhibitor within a Deepwater Subsea Facility, Offshore Brazil

Jordan¹,

Linares-Samaniego²,

Afonso³

2010

Proceedings of SPE International Conference on Oilfield Scale

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This paper presents field results and lessons learned from an FPSO, Offshore Brazil where a scale and corrosion inhibitor has been applied subsea to control both the deposition of scale and associated corrosion. The paper outlines the problems encountered when the initial scale inhibitor formulation was deployed in the field related to materials compatibility with the subsea manifold and the steps taken to develop and monitor an improved formulation. Problems that can affect product application in a subsea environment, including deposition of suspended solids within the chemical, hydrate formation, incompatibility of the chemicals with umbilical material and produced fluid, will all be addressed. The laboratory methods used to select the product along with measurement methods used in the field are also discussed. The validation of the laboratory selection methods in the field required the development of a monitoring program to establish base line control and to assess the degree of protection from scale deposition and corrosion across the process. The use of novel real time scale monitoring, as well as water chemistry tracking proved vital to the understanding of the efficiency of flow assurance within the processes and how treatment rates of the scale inhibitor and corrosion inhibitor could be optimised. This paper will outline in detail the particular issues associated with chemical injection to a subsea facility, many of which are currently being developed in the Gulf of Mexico, offshore West Africa and Brazil. This case study is a good example of lessons learned and sharing of best practice from another oil basin.

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Scale Inhibitor Squeeze Treatments Deployed From an FPSO in a Deepwater, Subsea Field in the Campos Basin

Cited by 7 publications

References 0 publications

The Development of a Scale Management and Monitoring Program for a High-Temperature Oil Field During the Production-Decline Phase of the Life Cycle

The Development of a Scale Management and Monitoring Program for a High-Temperature Oil Field During the Production-Decline Phase of the Life Cycle

The Optimisation of a Scale Management and Monitoring Program for During the Production-Decline Phase of the Life Cycle

Deployment, Monitoring and Optimisation of a Scale Inhibitor and Associated Corrosion Inhibitor within a Deepwater Subsea Facility, Offshore Brazil

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