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Sosorhaug E.,Talisman Energy | Jordan M.M.,NalcoChampion | McCartney R.A.,Oilfield Water Services Ltd | Stalker R.,Scaled Solutions Ltd. | And 2 more authors.
Society of Petroleum Engineers - SPE International Conference and Exhibition on Oilfield Scale 2014 | Year: 2014

The Blane field is a sub-sea oil and gas production development located in the southern part of the North Sea straddling the UK and Norwegian border. The field is expected to produce inorganic scale (BaSO4) when injection water containing sulphate breaks through in the production wells. This will require scale inhibitor squeezes from an intervention vessel to mitigate scale deposition. The wells were completed with long horizontal sections straddling multiple producing zones. This could potentially result in scale deposition severely reducing productivity if both formation water and injection water were to be produced simultaneously into the wells. Adding to the complexity, the perforation guns were left in the wellbore as part of the completion preventing any access to the perforation area. The distribution of scale inhibitor during a squeeze pumping operation could therefore be uneven leaving parts of the well poorly protected. In addition, the guns prevent physical removal of any type of materials in the well bore like asphaltenes, sand and scale which could plug off the perforations during a pumping operation with a well intervention tool; Wireline, coiled tubing, etc.. Injection water supplied from a host platform is used for pressure support of the reservoir. During the field development, the injection water was expected to contain mostly produced water reducing the scale potential considerably as it would have low sulphate content. When water injection started, very little produced water was being produced resulting in mostly seawater being available available for pressure support. Scale deposition in the well and around the well bore could therefore prove to be impossible to control unless reactions in the reservoir would reduce the scale potential or a reliable scale inhibitor squeeze method to mitigate scaling could be identified. This paper describes the joint effort of 6 different companies to identify the risks associated with the inorganic scaling during production and how a scale squeeze strategy was developed. The work included scale inhibitor selection, a geo-chemical study, and reservoir and near well bore simulations, sub-sea deployment selection, deciding on water chemistry and production monitoring and development of an overall management plan. Copyright 2014, Society of Petroleum Engineers. Source

Wilson M.J.,James Hutton Institute | Wilson M.J.,Tomsk Polytechnic University | Wilson L.,COREX UK Ltd. | Shaldybin M.V.,Tomsk Polytechnic University
Earth-Science Reviews | Year: 2016

Re-interpretation of R3 mixed-layer illite-smectite (I/S) as consisting only of thin (< 50 Å) illite leads to the question of whether this really matters in the context of the overall physico-chemical properties of the shales in which this clay material is found, such as in the unconventional hydrocarbon shale reservoirs of the USA. It is argued here that the distinction between regarding the clay mineralogy of these shales as partly smectitic or wholly illitic is important, particularly when one considers the interactions between charged clay surfaces and aqueous pore fluids. These interactions are broadly discussed within the framework of the double electric layer (DEL) theory which successfully accounts for a range of phenomena that are observed in colloidal sols of clay minerals dispersed in aqueous solutions of varied chemical composition. Particle interactions in these sols depend to a large extent on the thickness of the DEL. In general, this thickness is controlled by the balance between the external surface charge density of the clay particle and the electrolyte concentration of the aqueous solution, because the higher the surface charge density the thicker will be the DEL, and the more concentrated the aqueous solution the thinner will be the DEL. Although shales are not colloids, in situations where the pore size is similar to that of the thickness of the DEL the same principles that govern particle-fluid interactions in the colloidal state should still apply. It turns out that the pore size distribution in shales is probably mainly in the mesopore range (2-50 Å) and the lower part of this range certainly falls within the thickness of the DEL associated with highly charged particles. The external surface charge density of illite may be up to about 5 times greater than that of smectite and for this reason may be expected to be highly reactive, particularly when present as fine-grained high surface area particles, and to impact upon at least some of the physico-chemical properties of shale as a whole. The characteristics to be discussed include particle size, surface area, ion exchange properties, porosity, swelling and dispersion, and these, in turn, could affect various aspects of unconventional hydrocarbon reservoirs, particularly declines in permeability from initially promising values. Many other processes might be relevant such as creep behaviour of the lithology, which is heavily influenced by clay type and abundance, salt precipitation and induced downhole diagenesis. In addition, the cation exchange between the dominant clay mineral and the fluid used for hydraulic fracture is undoubtedly an issue that needs to be addressed. © 2016 Elsevier B.V. Source

Wilson M.J.,James Hutton Institute | Wilson M.J.,Tomsk Polytechnic University | Shaldybin M.V.,Tomsk Polytechnic University | Wilson L.,COREX UK Ltd.
Earth-Science Reviews | Year: 2016

The mineralogy of many of the major unconventional hydrocarbon shale reservoirs in the USA, which span practically the whole spectrum of Phanerozoic time, is reviewed from a survey of relevant published literature. This survey reveals that there is a remarkable uniformity in the mineralogy of these shales, both with regard to non-clay minerals but particularly to the clay minerals. It was found that the clay mineralogy of practically all of the shale reservoirs older than the Upper Cretaceous are dominated by illitic clays, both in discrete form and as illite-dominated, mixed-layer, illite-smectite (I/S). The layer stacking arrangement of the latter is of the long-range type described as R3, such that every smectite layer tends to be preceded and succeeded by three illite layers in a sequence like IIISIIIS. Such material is conventionally interpreted (a) as having formed from a smectite precursor, (b) as existing in MacEwan-type crystallites consisting of about 5 to 15 unit layers in thickness where there is three-dimensional regularity across the smectite interlayers, and (c) as having interlayers of a truly smectitic character. Using evidence from the fundamental particle concept of Nadeau et al. (1984b) this interpretation is rejected. Instead, it is proposed that R3-type I/S (a) forms de novo, crystallizing from pore waters of appropriate chemical composition in a particular pressure and temperature stability field, as it does in conventional sandstone reservoirs, (b) consists primarily of thin illite crystallites or crystals <. 50 Å in thickness, and (c) that the "smectite" interlayers can be accounted for by the ability of such thin illite stacks, which have no three-dimensional register between the fundamental particles when sedimented onto glass slides, to adsorb ethylene glycol between the particles so leading to a false diagnosis of "smectite". This interpretation could have major consequences on the physicochemical properties of the shale, a matter that is examined more closely in the second part of this review. © 2016 Elsevier B.V.. Source

Han L.,Royal Dutch Shell | Hicking S.,Royal Dutch Shell | Twycross J.,Royal Dutch Shell | El-Jamali S.,Royal Dutch Shell | And 2 more authors.
SPE - European Formation Damage Conference, Proceedings, EFDC | Year: 2014

This paper describes the design and qualification testing of high density oil based screen running fluids for an HPHT subsea gas field development in the Norwegian Sea. The field of interest contains gas bearing sandstones with permeabilities up to 5-10 Darcy buried at greater than 5000 m at high temperature and pressure (185 °C, 830 bar). The wells are designed to be completed with standalone screens. However, running screens in high density OBM has been a challenge for the industry due to the high solids load of such fluids. To qualify an HPHT screen running fluid, crucial to the economical development of this field, a rigorous fluid testing program was designed and carried out. The main drivers for the fluid qualification are to ensure that: • The fluid is stable at downhole temperature to allow the running of the screens to bottom without plugging • The fluid should remain mobile to allow easy backflow after a 28-day static period to allow subsequent well completion operations and back flow of the wells • The fluid should not plug the screens after the 28-day static period The fluids were first designed and tested in vendor laboratories to ensure good long term stability and mobility. This was followed by internal confirmation testing by the operator. Final qualification at a third party facility for stability and mobility was carried out at simulated downhole conditions using a purpose built HPHT cell incorporating a sand control screen. The results of the qualification program showed that a 1.90 sg oil-based fluid containing fine barite can deliver a feasible solution to the completion challenges for the HPHT field development. The designed fluids are stable, easy to backflow and will not plug the sand control screens. The learnings from this study will also be presented. Copyright 2014, Society of Petroleum Engineers. Source

Wilson M.J.,James Hutton Institute | Wilson L.,COREX UK Ltd. | Patey I.,COREX UK Ltd.
Clay Minerals | Year: 2014

The influence of individual clay minerals on formation damage of reservoir sandstones is reviewed, mainly through the mechanism of fine particle dispersion and migration leading to the accumulation and blockage of pore throats and significant reduction of permeability. The minerals discussed belong to the smectite, kaolinite, illite and chlorite groups respectively. These minerals usually occur in an aggregate form in reservoir sandstones and the physicochemical properties of these aggregates are reviewed in order to reach a better understanding of the factors that lead to their dispersion in aqueous pore fluids. Particularly significant properties include the surface charge on both basal and edge faces of the clay minerals and how this varies with pH, external surface area of both swelling and non-swelling clays, porosity and pore size distribution in the microand meso-pore size range and overall aggregate morphology. For non-swelling clays, and perhaps even for swelling clays, dispersion is thought to be initiated at the micro-or meso-pore level, where the interaction between the pore solution and the charged clay surfaces exposed on adjacent sides of slit-or wedge-shaped pores brings about expansion of the diffuse double electric layer (DDL) and an increase in hydration pressure. Such expansion occurs only in dilute electrolyte solutions in contrast to the effect of concentrated solutions which would shrink the thickness of the DDL and so inhibit dispersion. Stable dispersions are formed, particularly where the solution pH exceeds the isoelectric pH of the mineral, which is often at alkali pH values, so that both basal face and edge surfaces are negatively charged and the particles repel each other. The osmotic swelling of smectitic clays to a gel-like form, so effectively blocking pores in situ, is often invoked as an explanation of formation damage in reservoir sandstones. Such swelling certainly occurs in dilute aqueous solutions under earth surface conditions but it is uncertain that stable smectitic gels could form at the temperatures and pressures associated with deeply buried reservoir sandstones. © 2014 The Mineralogical Society. Source

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