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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.

Emadi A.,Heriot - Watt University | Emadi A.,COREX Uk Ltd. | Sohrabi M.,Heriot - Watt University
Proceedings - SPE Annual Technical Conference and Exhibition | Year: 2013

Low salinity waterflood (LSW) is a relatively new enhanced oil recovery (EOR) technique which has been reported to improve oil recovery in several laboratory experiments and some field trials. The general assumption among researchers is that LSW shifts wettability towards a more favourable state for oil recovery. Several hypotheses have been introduced in the literature as possible mechanisms involved in oil recovery by LSW e.g. fine migration and flow diversion, multi-component ion exchange (MIE), and rise in pH. However, a consistent theory to explain the process of wettability modification has not yet emerged. This paper presents the results of a comprehensive set of direct visualization (micromodel) experiments which investigate the low salinity effect (LSE) from a novel perspective. The visualization study, using reservoir-condition micromodels, shows that when low salinity brine comes in contact with certain crude oils, a large number of water micro-dispersions form at the oil/water interface within the oil phase. The formation and precipitation of these micro-dispersions can only be seen under high magnifications using our imaging system specifically designed for thin micromodels. The water micro-dispersions do not form when the oil is in contact with a high salinity brine and when they form due to low salinity of the brine, they coalescence as soon as the oil comes in contact with a high salinity brine. In our micromodel tests, when a mixed-wet micromodel and high salinity connate water were utilized, the formation of these micro-dispersions was associated with a slight change in the wettability and redistribution of fluids. We hypothesize that formation of the micro-dispersions results in additional oil recovery through two separate mechanisms; (1) depletion of the oil/water interface from natural surface active materials, resulting in wettability alteration and, (2) swelling of droplets of high salinity connate water. The results of this study introduce water/oil interactions and formation of water micro-dispersions as a potential mechanism for wettability alteration and improved oil recovery in low salinity water injection. Copyright 2013, Society of Petroleum Engineers.

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.

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.

Wilson L.,Corex UK Ltd. | Wilson M.J.,James Hutton Institute | Green J.,Corex UK Ltd. | Patey I.,Corex UK Ltd.
Earth-Science Reviews | Year: 2014

This paper critically reviews the clay mineralogy of reservoir sandstones in the North Sea, as assessed from peer-reviewed papers in the literature as well as from the authors' personal experience, in the particular context of formation damage. The most common clay minerals in these sandstones are well-crystallized kaolinite, mainly occurring as pore-filling vermiform and booklet-like aggregates, illitic clays, usually in the form of pore-filling networks of thin lath-like, filamentous or hairy particles, but less frequently as platy aggregates, and chlorite, most commonly found as pore-lining aggregates of interlocking, well-developed, bladed crystals. All these clay minerals are authigenic (diagenetic) in origin. Discrete smectite is rarely found in North Sea reservoir sandstones, even though associated pelitic rocks may contain an abundance of this type of clay mineral.The crystallization of kaolinite in these sandstones has been attributed to a variety of stages in the paragenetic sequence, particularly in relation to the authigenic formation of calcite and quartz. However, most evidence suggests that vermiform kaolinite is a product of early diagenesis at temperatures ranging from surface to 40. °C, either before or contemporaneously with carbonate cementation and before the formation of quartz overgrowths. Exceptions to this generalization may occur because of complex basin histories involving tectonic uplift and migration of fluids of varying chemistry. With increasing depth of burial and at higher temperatures, the kaolinite in these reservoir sandstones converts at least partially to dickite, which occurs in more blocky aggregates. Consideration of recent theoretical studies of kaolinite indicate that at pH values >. 8 all face and edge surfaces will be uniformly negatively charged, strongly suggesting that in these circumstances the kaolinite will become disaggregated to form stable dispersions capable of migration where there is sufficient force of hydrodynamic flow.The illitic clay in North Sea reservoir sandstones is usually described in terms of two discrete phases, namely illite itself and mixed-layer illite-smectite (I/S). Evidence is presented to show that in all probability only one illitic phase exists in these sandstones and that the mixed-layer phase in reality consists only of very thin illite (<5nm in thickness). Such material when sedimented on glass slides adsorbs ethylene glycol between its thin particles and yields an XRD pattern identical to that of I/S, usually of a regularly ordered (R3) form. In this case, however, diffraction is an interparticle phenomenon and the "smectite" layers detected are more apparent than real. In the North Sea reservoir sandstones, illitic material is considered to exist in both pore-filling and pore-lining modes, with the latter forming at low temperatures very early in the paragenetic sequence, perhaps even in equilibrium with depositional pore waters. In contrast, the pore-filling illitic clay is thought to have formed at higher temperatures, in excess of 100°C, following deeper burial. In this paper, it is argued that so-called pore-lining illite is sometimes an artefact of the customary drying procedure of the sandstone samples prior to examination by SEM or optical microscopy. Such procedures cause some or all of the delicate pore-filling illite filaments to shrink back against the pore walls so producing the appearance of a pore-lining mode. Evidence against a separate early phase of illite formation in pore-lining mode includes K-Ar dating showing that the age of North Sea illites is always much later than the stratigraphic age of the sediment, oxygen isotope evidence showing that North Sea illites have usually formed at relatively high temperatures (>100°C), SEM observations showing that putative pore-lining illite actually consists of dense masses of compacted illite fibres identical to those that fill pores, and finally the similar chemical compositions of both pore-lining and pore-filling illite showing them both to be of a muscovitic or phengitic nature. It is probable that the illitic clay in North Sea reservoir sandstones is highly dispersible and is prone to redistribution, particularly in the Na+-saturated state, and because of its very fine particulate form would therefore be readily mobilized by hydrodynamic forces.Finally, several illustrative examples are presented to show that clay migration during fluid injection is a probable cause of formation damage in North Sea reservoir sandstones. SEM observations following fluid treatments clearly show the breakup of kaolinite aggregates whereas the evidence for illite mobilization consists of the appearance of large holes in the network of pore-filling illite laths. In addition to this, analytical evidence shows that both kaolinite and illite particles have exited core samples following fluid or gas flow, thereby proving their mobility within the core. © 2014 Elsevier B.V.

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.

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..

Green J.,COREX UK Ltd. | Cameron R.,COREX UK Ltd. | Patey I.,COREX UK Ltd. | Nagassar V.,Centrica | Quine M.,Centrica
SPE - European Formation Damage Conference, Proceedings, EFDC | Year: 2013

Formation damage testing is commonly used to gather information and aid in risk-reduction when making operational decisions. The nature of laboratory testing means that it is a higher risk to rely on permeability and pressure measurements alone, so various techniques (including scanning electron microscopy and thin section) are used to gather additional information and aid interpretation. The current techniques provide excellent high-resolution data but are limited in terms of capturing the change throughout an entire core sample. The paper presents a new approach which utilises micro-CT scanning to produce high-resolution data of entire core samples. The images of core produced are superior to those from the commonly-used medical scanners, and give insight into core properties as well as areas such as drilling mud constituents infiltration, mud-cake structure and thickness, and alterations in the pore network. Through a technique that we have called "difference mapping", data sets captured before and after laboratory testing are compared to reveal the distribution of changes within samples. Difference maps can be used to provide additional interpretation of tests results as well as combining with current techniques to target their sampling locations. The combination of laboratory data with tools that allow visualisation of both the distribution and nature of damaging mechanisms makes laboratory data more valuable and therefore decreases risk in operational decision-making. The technique is illustrated by a case study from Centrica's South Morecambe gas field. Here a series of experiments were carried out to aid in the selection of drilling mud for a cased & perforated well. Whilst permeability was relevant, it was most important to have a fluid that did not contribute deep damaging mechanisms or produce high fluid losses. Laboratory test data showed very significant reductions in permeability, which would normally be a concern if there was not an understanding of the nature of damage. Micro-CT scanning, in combination with geological analysis, showed that the damaging mechanisms were concentrated within the drilling mud-cake, attachment of the drilling mud-cake to the core sample, and drilling mud constituents within the first few pores of the core sample. Only scattered change, caused by some drilling mud filtrate retention and clay fines mobilisation, was seen deeper in the majority of samples; in a cased & perforated scenario the vast majority of damage would therefore be expected to be bypassed. This illustrated the value of the combination of micro-CT scanning and geological techniques to allow greater insight and more meaningful conclusions. © (2013) by the Society of Petroleum Engineers.

News Article | December 22, 2016
Site: www.prnewswire.com

HOUSTON, Dec. 22, 2016 /PRNewswire/ -- Premier Oilfield Laboratories, LLC (POL) announced today that it has acquired COREX UK Ltd. (COREX). Established over 40 years ago, COREX is an international provider of analytical services for the oil and gas industry, helping to improve...

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