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Patent
Corex UK Ltd | Date: 2017-02-08

A method of analysing a subterranean drilled core sample 10 is disclosed. The steps followed are:- a) providing a drill core sample 10 taken from a subterranean formation; b) producing high-resolution data of at least a section of the drill core sample 10 and creating a 3D before test skeleton of the sample 10 using that data; c) mimic wellbore operations using reservoir conditions core floods; d) producing high-resolution data of at least a section of the drill core sample 10 and creating a 3D after test skeleton of the sample using that data; e) identifying and/or segregating one or more formation damage mechanisms 12 by subtracting the 3D before test skeleton from the 3D after test skeleton to create a 3D change skeleton which shows all the formation damage mechanisms 12; and f) 1) identify one or more individual formation damage mechanisms 12, by conducting segmentation including performing one or more diagnostic analysis techniques on at least a section of the drill core sample 10 and generating individual or combinations of simulated 3D skeletons; and 2) determining the effect of said formation damage mechanism(s) 12 on a chosen characteristic of interest of said drill core sample 10.


Patent
COREX UK Ltd | Date: 2015-04-02

A method of analysing a subterranean drilled core sample 10 is disclosed. The steps followed are: a) providing a drill core sample 10 taken from a subterranean formation; b) producing high-resolution data of at least a section of the drill core sample 10 and creating a 3D before test skeleton of the sample 10 using that data; c) mimic wellbore operations using reservoir conditions core floods; d) producing high-resolution data of at least a section of the drill core sample 10 and creating a 3D after test skeleton of the sample using that data; e) identifying and/or segregating one or more formation damage mechanisms 12 by subtracting the 3D before test skeleton from the 3D after test skeleton to create a 3D change skeleton which shows all the formation damage mechanisms 12; and f) 1) identify one or more individual formation damage mechanisms 12, by conducting segmentation including performing one or more diagnostic analysis techniques on at least a section of the drill core sample 10 and generating individual or combinations of simulated 3D skeletons; and 2) determining the effect of said formation damage mechanism(s) 12 on a chosen characteristic of interest of said drill core sample 10.


Emadi A.,Corex UK Ltd | Khabibullin R.,Wintershall | Patey I.,Corex UK Ltd | Grin Z.A.,Wintershall | And 2 more authors.
IOR NORWAY 2017 - 19th European Symposium on Improved Oil Recovery: Sustainable IOR in a Low Oil Price World | Year: 2017

The asphaltene related issues are known to cause operational problems during well drilling, completion and production life of oil reservoirs. In many cases, this has a significant impact on the development of marginal fields due to the cost associated with inhibition and/or remediation treatment. Therefore, the understanding of asphaltene properties and deposition potential is an important consideration in the reservoir development and design of the EOR/IOR processes. This paper introduces a new approach that tries to enhance our understanding of asphaltene deposition by adding petrography analysis and Micro-CT studies to conventional PVT type asphaltene analysis and coreflood tests. The application of this approach for a CO2 injection process is presented as a case study which shows how the addition of interpretive geological analysis can assist our understanding of asphaltene deposition and the mitigation solutions. The main objective of this study was to investigate asphaltene deposition and permeability impairment during CO2/Hydrocarbon flow in the reservoir rock. Asphaltene onset pressure (AOP) and CO2 titration tests were performed using SDS and filtration techniques to characterize asphaltene phase behaviour. Based on the results of the characterization tests, coreflood tests were designed and carried out using reservoir oil and CO2 with CO2 injection ratios increasing from 0.25 to 1.00. Effective permeability measurements were undertaken before and after test to determine the level of permeability alteration due to asphaltene deposition and fluid rock interactions. Comparison of the permeability data before and after the tests shows average permeability reductions of 31% and 13% for two samples with initial permeability of 23.42 and 251.80 mD, respectively. The inverse relationship between permeability loss and original permeability is believed to be due to the smaller size of pore throats in the low permeability sample which boost effect of damaging mechanisms on the permeability. The interpretive geological analysis (micro-CT, thin section analysis and dry SEM) showed the permeability loss can be attributed to (1) Fluid-Fluid interactions between CO2 and reservoir oil which results in deposition of asphaltene and, (2) Rock-Fluid interactions between CO2 and reservoir rock which results in clay fines redistribution and removal. The results show that the effect of asphaltene deposition in porosity change is significantly higher than the effect of clay fine redistribution. The micro-CT analysis also show asphaltene deposition takes place soon after mixing between crude oil and CO2.


Emadi A.,Corex UK Ltd | Guitian J.,Repsol | Worku T.,Repsol | Cornwall C.,Corex UK Ltd | And 2 more authors.
IOR NORWAY 2017 - 19th European Symposium on Improved Oil Recovery: Sustainable IOR in a Low Oil Price World | Year: 2017

Carbonate reservoirs are estimated to contain around half of the total oil and gas reserves in the world. Exploitation of these reservoirs is specifically challenging and their recovery factor is generally lower than clastic reservoirs, due to their structural complexity, local heterogeneities, fracture porosity and the oilwet-nature of the carbonate rocks. The principle objective of this study was to investigate through laboratory experimentation, the feasibility of improving oil recovery from a fractured tight carbonate reservoir by spontaneous and forced imbibition of a compatible low salinity water (LSW), with and without a surfactant. To facilitate this objective, core material and reservoir crude oil from an active field were combined with reservoir temperature and wettability restoration, in a series of complementary tests, supported by compelling photographic images. Wettability screening of the restored core samples confirmed an oil-wet system with small tendency for water imbibition, which is typical behavior of such low permeability carbonates. In spontaneous imbibition tests, the samples were exposed to resident formation brine, followed by a LSW (2253ppm), with and without surfactant. The start point for the two-stage imbibition sequence was a residual oil saturation (∼ 32%PV), which was representative of the target reservoir, established by centrifuge displacement. Exposure to the formation brine resulted in no additional recovery. In contrast the LSW prompted a reduction in the residual oil saturation of 20.47% (9%OOIP). With the addition of a surfactant to the LSW, there was an apparent improvement in the effectiveness of the displacement process, which lowered the residual oil saturation by 27.02% (13.14%OOIP). To assess the benefits of forced imbibition of the LSW, a combined "soak-and-drive" sequence was deployed. For a core sample with a restored wettability and an established residual oil saturation of ∼ 32% PV, the sequencing almost doubled the additional oil production when compared with spontaneous imbibition tests using the same fluid. Wettability modification has often been cited as a possible mechanism for the success of LSW, particularly in clastic lithologies. An alternative mechanism for improving oil production has recently been introduced in the technical literature, described as an osmosis like phenomenon. This paper explores the possibility of this type of oil displacement in the context of a carbonate reservoir, with the movement of the LSW from the fracture network into the matrix blocks. The data generated by the experimentation, coupled with the progressive series of photographic images, are presented to give credence to the suggested mechanism.


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.


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..


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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