Modelling of Gel Diverter Placement in Horizontal Wells

Menzies, N A; Mackay, Eric James

doi:10.2118/56742-ms

Cited by 14 publications

(3 citation statements)

References 10 publications

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“…Although the wells closest to the injectors are known to experience severe crossflow 14,17 , which makes correct inhibitor placement difficult, the evidence does not suggest that all the Zone 1 wells are inadequately protected. This implies that partial mixing is occurring in the aquifer, leading to some loss of barium away from the wellbore, which is in fact beneficial.…”

Section: Well-by-well Analysis Of Brine Composition Datamentioning

confidence: 96%

Implications of Brine Mixing in the Reservoir for Scale Management in the Alba Field

Paulo

Mackay²,

Menzies

et al. 2001

Proceedings of International Symposium on Oilfield Scale

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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThis paper brings the discussion on brine mixing initiated at the 1999 SPE Symposium on Oilfield Scale full circle, and suggests that different scaling regimes may exist in any given reservoir that should impact the scale management strategy. The initial paper by White et al. (1999) identified lower than expected barium levels in many wells in the Alba field, and raised the question of where scale deposition is occurring. A follow-up paper at the same meeting the following year by Mackay and Sorbie (2000) identified from a theoretical standpoint where brine mixing should be expected, and suggested that significant scale deposition may occur deep within the reservoir, particularly where a large proportion of injected water sweeps through the aquifer. The current paper seeks to apply that theoretical analysis to the Alba field, on a well-by-well basis, to establish whether diagnostic tests can identify which wells should be treated conventionally, and which require special attention.Firstly, production data and produced brine compositions are analysed to identify any recurring patterns. Wells are then classified and grouped according to various types based on this analysis. Well properties such as location within the reservoir and orientation to the flood front are then compared to identify whether they can be used to give a similar grouping of wells. Three principal zones are identified, with position relative to the injection wells and the aquifer identified as key parameters. Secondly, the flow patterns around each well are studied using the existing reservoir flow model. Modelling the dynamic mixing patterns throws further light on the differences between the zones, with scale dropout predicted in the aquifer in some areas, and in the oil-leg in others.Recommendations are made regarding the treatment of existing wells and the optimum positioning, from a scale prevention perspective, of any new wells.

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Section: Well-by-well Analysis Of Brine Composition Datamentioning

confidence: 96%

Implications of Brine Mixing in the Reservoir for Scale Management in the Alba Field

Paulo

Mackay²,

Menzies

et al. 2001

Proceedings of International Symposium on Oilfield Scale

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“…Particular reference is made to a case-study in the North Sea oilfield where barium sulphate scale formation occurs due to mixing of incompatible injected seawater and formation brine. 1 Oilfield scales lead to formation damage as well as wellbore damage. Scales are deposits/coatings which form on surfaces of metals, rocks and other materials.…”

Section: Introductionmentioning

confidence: 99%

An Experimental Study of Oil Fields Scale Analysis and Dissolution Test Using Acidizing Fluids

Dankwa

2024

TPE

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Formation damage reduces permeability of reservoirs thereby reducing well productivity. One of the methods that is used to remove formation damage is acidization. Oilfield scales are basically mineral scales that are formed during petroleum production and have the tendency to cause wellbore damage. Formation of oilfield scales result predominantly from over saturation of dissolved minerals in oil and gas produced water. In this study, scale samples have been analysed and identified using x-ray diffractometry. X-Ray diffractometry was used to identify minerals present in the wellbore scales. The X-Ray diffractometry results confirmed the presence of seventeen different minerals in the scales and these have been classified as carbonates, silicates and phosphates. Matrix acidizing fluids have also been designed and formulated to test the capability to dissolving the scales. 10% and 15% HCl (regular acids) as well as xylene and diesel were used on the scales to ascertain their dissolution capabilities. None of these three fluids was able to completely dissolve the sample scales because the mineralogical compositions revealed by XRD were mainly the HCl insoluble minerals such as Petalite, Xenotite, etc. Only 10% mineral composition of the scales identified were HCl soluble. The results of this study prove that, X-Ray Diffractometry must precede any action taken to remove/treat oilfield scales, especially when considering chemical dissolution. This will prevent wastage and save money and time.

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“…At present there is little literature relating to the use of viscosified solutions for scale inhibitor treatments, other than for temporary diversion. [9][10][11][12][13][14][15][16] Although viscous treatments are not usually associated with scale inhibitor treatments, the viscosity of the main chemical injection pill (typically 10 -20 % scale inhibitor dissolved in sea water) will normally be higher than that of the overflush (seawater). Moreover, in other less conventional treatments involving higher viscosity main treatments, including for example emulsified chemical treatments, the overflush used is generally a much lower viscosity fluid (diesel).…”

Section: Squeeze Placement In Horizontal Wells -Introductionmentioning

confidence: 99%

Potential Application of Viscosified Treatments for Improved Bullhead Scale Inhibitor Placement in Long Horizontal Wells – A Theoretical and Laboratory Examination

Stalker¹,

Graham²,

Oliphant

et al. 2004

All Days

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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractScale control in subsea horizontal wells is recognised as a particular technical and economic challenge, especially if effective chemical placement cannot be achieved through conventional bullhead squeeze treatments.When long horizontal or highly deviated wells produce from areas of high permeability contrast and high wellbore crossflow, coil tubing operations can often be the only manner in which effective chemical placement can be guaranteed. The costs associated with such treatments are extremely expensive and often prohibitive when compared with conventional bullhead operations. Such aspects were recognized as a particular risk for successful chemical treatments in the Draugen field, operated by Norske Shell. The Draugen field is located in the environmentally sensitive Haltenbank area of the Norwegian Continental Shelf, and produces oil from 6 horizontal (>1,000 ft.) wells completed with pre-packed resin screens to achieve effective sand exclusion. A moderate barium sulphate scaling potential was anticipated following sea water breakthrough requiring squeeze treatments. In order to improve chemical placement in this field and reduce the requirement for coil tubing interventions for squeeze treatment, work was initiated to investigate the potential use of viscosified fluids to improve downhole chemical placement.A range of viscosifying agents was selected following detailed literature review based upon the rheology that was expected to lead to improved chemical placement. This included common water control additives such as xanthan and HEC (hydroxyethylcellulose) biopolymers and formulated water in oil (WIO) or oil in water (OIW) emulsions. Various formulations were selected that would either remain stable (higher viscosity) or to break (to low viscosity) at reservoir temperature. It should be noted, however, that viscosities were selected far below those normally applied in water shut off or multi-stage chemical diversion treatments. A series of formation damage core flood experiments has been conducted using analogue cores to ensure that the various formulations were non damaging, allowing rapid recovery to pre-treatment effective oil permeability. In addition, more sophisticated core flooding equipment was designed to examine chemical placement and recovery in zones of different permeability.In summary, this paper presents a literature review describing the properties of different viscosifying agents and their potential applicability for improving bullhead scale inhibitor squeeze treatments. Core flood studies on viscosifying agents with selected rheological properties will then be presented to demonstrate the potential advantages of such applications for improved chemical placement by bullhead application in horizontal wells.

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Modelling of Gel Diverter Placement in Horizontal Wells

Abstract: This paper was prepared for presentation at the 1999 SPE Annual Technical Conference and Exhibition held in Houston, Texas, 3–6 October 1999.

Cited by 14 publications

References 10 publications

Implications of Brine Mixing in the Reservoir for Scale Management in the Alba Field

Implications of Brine Mixing in the Reservoir for Scale Management in the Alba Field

An Experimental Study of Oil Fields Scale Analysis and Dissolution Test Using Acidizing Fluids

Potential Application of Viscosified Treatments for Improved Bullhead Scale Inhibitor Placement in Long Horizontal Wells – A Theoretical and Laboratory Examination

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