Effective Management of Scaling from and Within Carbonate Oil Reservoirs, North Sea Basin

Jordan, Myles Martin; Kemp, Simon J.; Sørhaug, Eyvind; Sjursaether, K.; Freer, B.

doi:10.1205/02638760360596919

Cited by 18 publications

(8 citation statements)

References 2 publications

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“…These approaches require the pipe wall to be smooth and of uniform thickness [18], while the wall thickness of conventional casing is rather poorly controlled, with specifications allowing for 12.5% variability [56]. Alongside mineral scaling, present in many existing wellbores [34,62], significant lubrication issues are therefore expected [30], which in turn could cause swaging to induce considerable damage to the casing tube [18]. Given these difficulties, alternative approaches are needed for expanding conventional wellbore casings to seal leakage pathways outside of the casing in existing wellbores, e.g.…”

Section: Introductionmentioning

confidence: 99%

Reaction-driven casing expansion: potential for wellbore leakage mitigation

2017

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It is generally challenging to predict the postabandonment behaviour and integrity of wellbores. Leakage is, moreover, difficult to mitigate, particularly between the steel casing and outer cement sheath. Radially expanding the casing with some form of internal plug, thereby closing annular voids and fractures around it, offers a possible solution to both issues. However, such expansion requires development of substantial internal stresses. Chemical reactions that involve a solid volume increase and produce a force of crystallisation (FoC), such as CaO hydration, offer obvious potential. However, while thermodynamically capable of producing stresses in the GPa range, the maximum stress obtainable by CaO hydration has not been validated or determined experimentally. Here, we report uniaxial compaction/expansion experiments performed in an oedometer-type apparatus on precompacted CaO powder, at 65°C and at atmospheric pore fluid pressure. Using this set-up, the FoC generated during CaO hydration could be measured directly. Our results show FoC-induced stresses reaching up to 153 MPa, with reaction stopping or slowing down before completion. Failure to achieve the GPa stresses predicted by theory is attributed to competition between FoC development and its inhibiting effect on reaction progress. Microstructural observations indicate that reaction-induced stresses shut down pathways for water into the sample, hampering ongoing reaction and limiting the magnitude of stress build-up to the values observed. The results nonetheless point the way to understanding the behaviour of such systems and to finding engineering solutions that may allow large controlled stresses and strains to be achieved in wellbore sealing operations in future.

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Section: Introductionmentioning

confidence: 99%

Reaction-driven casing expansion: potential for wellbore leakage mitigation

2017

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“…As a backup to these predictions, careful monitoring of the produced brines (ions and scale inhibitor) and measurement of suspended solids to detect the presence of barium sulphate crystals 33 is being performed to evaluate both laboratory measured and the field derived MIC as seawater fractions change in each well.…”

Section: Implications For Scale Managementmentioning

confidence: 99%

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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“…3,4,5]. It has also been noted that the SI/carbonate interaction may be more complex than a simple adsorption/desorption process [4]. In this work, we present the initial findings of a systematic study of these interactions focusing here on the effect of pH on the SI/carbonate interactions for a phosphonate (DETPMP) scale inhibitor.…”

Section: Introductionmentioning

confidence: 95%

“…Field studies have appeared in the literature which look at the deployment of scale inhibitors in carbonate reservoirs [e.g. 3,4,5]. It has also been noted that the SI/carbonate interaction may be more complex than a simple adsorption/desorption process [4].…”

Section: Introductionmentioning

confidence: 99%

Scale Inhibitor Core Floods in Carbonate Cores: the Influence of pH on Phosphonate-Carbonate Interactions

Baraka-Lokmane

Sorbie

2004

All Days

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Scale inhibitor core floods were performed using outcrop Jurassic Portlandian chalk cores. The effect of pH on the phosphonate-carbonate interaction was studied by performing core floods at various fixed injected pH values (pH ∼6, 4, and 2). The scale inhibitor (SI) used in these core floods was 5000 ppm active DETPMP adjusted to the application pH for that core flood. Effluent concentrations of scale inhibitor, lithium tracer, calcium and magnesium are measured, as are the effluent pH values. This thorough set of measurements makes it possible to interpret the inhibitor/carbonate interaction mechanisms quite clearly.Some carbonate dissolution is evident in all core floods which is quantified in our floods and, as expected, the degree of dissolution increases as pH decreases. The pH 2 core flood (C4) showed the highest carbonate dissolution to the extent that the fluid induced the formation of a worm hole through the core. Flood C3 carried out at pH 4 showed more carbonate dissolution than in floods carried out at pH 6, as well as giving high pH (~7) effluents. There is higher interaction between the injected solutions and the rock material in flood C3 (SI retention, Γ ≈ 4.5 mg/g), and an increase in permeability between the pre-treatment and post treatment stages (~13 %).All floods were modelled using a well established methodology [1,2]. For the high pH floods (pH 6) the SI return curves were modelled very accurately using an adsorption isotherm which appears to provide an excellent description of the SI/carbonate rock interaction. For the lower pH floods (pH 4 and 2), a reasonably good, but not perfect, match was obtained using a "pseudo-adsorption isotherm" approach. However, a more complete description of the SI /rock interaction involving the role of Ca 2+ is required in order to accurately model all of the features of the phosphonate/carbonate interaction. TX 75083-3836, U.S.A., fax 01-972-952-9435. The sponsors of the Heriot -Watt University, Flow Assurance and Scale Team (FAST) JIP are thanked for their support, input and permission to publish this work: Baker Petrolite, BioLab,

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Effective Management of Scaling from and Within Carbonate Oil Reservoirs, North Sea Basin

Cited by 18 publications

References 2 publications

Reaction-driven casing expansion: potential for wellbore leakage mitigation

Reaction-driven casing expansion: potential for wellbore leakage mitigation

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

Scale Inhibitor Core Floods in Carbonate Cores: the Influence of pH on Phosphonate-Carbonate Interactions

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