GeoArabia, Journal of the Middle East Petroleum Geosciences最新文献

{"title":"Petrophysical properties evaluation of tight gas sand reservoirs using integrated data of NMR, density logs and SCAL. 9th Middle East Geosciences Conference, GEO 2010.","authors":"G. Hamada","doi":"10.3997/2214-4609-PDB.248.050","DOIUrl":"https://doi.org/10.3997/2214-4609-PDB.248.050","url":null,"abstract":"Many tight formations are extremely complex, producing from multiple layers with different permeability that is often enhanced by natural fracturing. The complexity of these reservoirs is attributed to: (1) low porosity and low permeability reservoir; and (2) the presence of certain clay minerals like illite, kaolin and micas in pores. Evaluation of tight gas sand reservoirs represents difficult problems. Determination of petrophysical properties using only conventional logs is very complicated. Nuclear magnetic resonance (NMR) logs differ from conventional neutron and density porosity logs. NMR signal amplitude provides detailed porosity free from lithology effects and radioactive sources and relaxation times give other petrophysical parameters such as permeability, capillary pressure, the distribution of pore sizes and hydrocarbon identification. Using of NMR on an individual basis or in combination with density log and SCAL data provides better determination of petrophysical properties of tight gas sand reservoirs.\u0000\u0000This study concentrates on determination of three petrophysical parameters of tight gas sand reservoirs: (1) Determination of detailed NMR porosity in combination with density porosity, DMR. It is found that DMR porosity method is a gas corrected porosity, and independent facies porosity model. (2) NMR permeability, KBGMR, is based on the dynamic concept of gas movement and bulk gas volume in the invaded zone. It is concluded that KBGMR is a facies independent technique, and this is the most important value of this technique. (3) Capillary pressure derived from relaxation time T2 distribution could be used for formation saturation measurements especially in the transition zone. It is found that the assumptions of capillary pressure approximation from T2 distribution can be applied in gas wells as well with some consideration due to gas and mud filtrate effects.","PeriodicalId":275861,"journal":{"name":"GeoArabia, Journal of the Middle East Petroleum Geosciences","volume":"88 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2010-03-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"123242407","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Mississippi Valley Type (MVT) mineralization in the Khuff C reservoirs, Saudi Arabia. 9th Middle East Geosciences Conference, GEO 2010.","authors":"R. F. Lindsay","doi":"10.3997/2214-4609-PDB.248.451","DOIUrl":"https://doi.org/10.3997/2214-4609-PDB.248.451","url":null,"abstract":"Mississippi Valley Type (MVT) mineralization emplaced pyrite, sphalerite, galena, and gangue minerals, such as saddle (baroque) dolomite into the C carbonate of the Khuff Formation, of Late Permian age. In most cases small percentages of MVT mineralization had been identified in several Khuff reservoirs, both onshore and offshore. In one particular case MVT mineralization was represented by complete replacement of carbonate beds and consisted of multiple, thick layers of mineral deposits that contained moldic porosity. X-ray diffractometry confirmed the presence of pyrite, sphalerite, and galena. \u0000\u0000In all cases, when MVT mineralization was identified it was located within the Khuff C carbonate immediately above the Khuff D evaporite. Major faults are thought to have delivered iron, zinc, and lead-rich fluids up-section from the basement or red beds that overlie the basement. Metal-rich fluids are considered to have derived sulfur by dissolution of the Khuff D evaporite and precipitated MVT minerals above the evaporite. This process essentially created a mixing zone to mix metals with sulfur as fluids moved up the fault zone in pulses, “squirt up a fault,” during late Mesozoic and/or Tertiary deformation.","PeriodicalId":275861,"journal":{"name":"GeoArabia, Journal of the Middle East Petroleum Geosciences","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2010-03-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131124892","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"The impact of geostatistical model parameters from fluid flow: Detailed modeling of the large scale steamflood pilot (LSP) area, Wafra First Eocene Reservoir, Partitioned Neutral Zone (PNZ). 9th Middle East Geosciences Conference, GEO 2010.","authors":"W. S. Meddaugh","doi":"10.3997/2214-4609-PDB.248.184","DOIUrl":"https://doi.org/10.3997/2214-4609-PDB.248.184","url":null,"abstract":"The First Eocene reservoir at Wafra Field in the PNZ is a Paleocene – Eocene age dolomite reservoir. The 40-acre, LSP steamflood project consists of 56 new wells (producers, injectors, and temperature observation wells), of which four are cored through the producing interval. The project area also includes four older wells, one of which was cored. Semivariogram models computed from the LSP wells (25-100 m well spacing) have correlation lengths on the order of 200-300 m whereas previous full field studies determined correlation lengths of 1500-2000 m using the primary development wells (500 m typical spacing). To test the impact of semivariogram model parameters and data density on fluid flow response five sets of static reservoir models were built. The fine scale static models (5 m areal grids, 4.5 million total cells) were simulated without up-scaling using 3-D streamline simulation. The dynamic scenarios selected were designed to reduce the noise of well distance, sweep direction and material balance error on the results. Analysis of variance (ANOVA) shows, with above 95% confidence, that models built using short semivariogram ranges have significantly higher recovery than models built using large semivariogram range. The conditioning well density does not significantly impact recovery.\u0000\u0000The effect of areal grid size was also examined. Static models were generated using 10 m, 20 m, and 40 m areal grid sizes and fluid flow response investigated using 3-D streamline simulation. The results suggest that grid size may also significantly impact recovery as models generated using the 40 m grid size gave more optimistic results compared to models generated using the smaller areal grid sizes.","PeriodicalId":275861,"journal":{"name":"GeoArabia, Journal of the Middle East Petroleum Geosciences","volume":"17 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2010-03-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"123701858","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Determination of surface relaxivity from NMR T2 measurements. 9th Middle East Geosciences Conference, GEO 2010.","authors":"A. Ashkar","doi":"10.3997/2214-4609-PDB.248.342","DOIUrl":"https://doi.org/10.3997/2214-4609-PDB.248.342","url":null,"abstract":"Nuclear magnetic resonance (NMR) is a very useful tool to determine rock properties. The NMR responds to the hydrogen contained within rocks and can be related in a direct or indirect way to porosity, pore-size distribution, rock permeability, capillary pressure, wettability and water saturation. The magnitude of the T2 signal is used to obtain the matrix independent porosity. Bound and moveable water can be estimated using the relationship between response and saturation. Empirical relationships can be used to several petrophysical properties, however, more detailed information is needed on surface relaxivity.\u0000\u0000To determine the effective surface relaxivity and establish a methodology, sandstones ranging from tight gas to poorly lithified sands were analyzed. The tests performed included conventional core analysis (porosity-permeability), back scattered image analysis (BSI), and NMR T2 relaxation on both fully saturated and drained conditions. The permeability of the samples ranges from 0.01 to 1000 mD and their porosities between 2 to 15%. The mean T2 of the brine saturated samples ranged from 0.8 to 400 ms. Arithmetic average of T2 cutoff (calculated as the point where Swi intercepts the T2 distribution) is 39.2 ms however values ranged between 1.45 ms and 242 ms where clay content played a key factor in reducing cutoff time. Back scattered images were used to establish the link between T2 relaxation and pore area. This relationship was then used to obtain the surface relaxivity.\u0000\u0000This presentation shows an innovative methodology to calculate the effective surface relaxivity using the signal generated from mean T2 relaxation with the objective of obtaining a better understanding of the NMR capabilities in assessing in situ reservoir properties. The methodology combines pore volume from NMR and BSE image analysis. However, in the case that image data were not available a correlation has been generated, using a large number of samples, which can be used to obtain surface relaxivity only from NMR T2 data. The surface relaxivity and T2 distribution can then be used to determine formation capillarity and in consequence be able to model the saturation height function to provide an input to the geological static model. The advantage of this method comes from the direct use of actual data, while the number of samples analysed enables the final outcome to be generalised, and therefore suitable to be used as an empirical approach when experimental results are not available.","PeriodicalId":275861,"journal":{"name":"GeoArabia, Journal of the Middle East Petroleum Geosciences","volume":"22 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2010-03-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127829141","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Effects of microfacies and diagenesis on petrophysical properties of Sarvak Formation, Fars Area, southern Iran. 9th Middle East Geosciences Conference, GEO 2010.","authors":"P. G. Zadeh, M. Adabi","doi":"10.3997/2214-4609-pdb.248.295","DOIUrl":"https://doi.org/10.3997/2214-4609-pdb.248.295","url":null,"abstract":"The Lower to Upper Cretaceous (Albian - Turonian) Sarvak Formation, the second major oil and gas reservoir in Zagros Basin of southern Iran, is principally composed of carbonates with minor shale. Fifteen microfacies were recognized from 287 meters of core, and 329 thin sections (colored with red Alizarin) were collected for petrographic analysis, together with analysis of core and well logs. Petrophysical properties of carbonates are controlled in part by the original depositional texture, but also largely by subsequent diagenetic processes. The sedimentary and diagenetic processes together control the arrangement, distribution and orientation of the major constituents, the open space and pathways, the fractures and the stylolites in the rock. When working with reservoir quality of carbonate reservoir rocks, these main fabric elements have to be considered.\u0000\u0000In this study, the microfacies were deposited in lagoon, back reef (leeward), reef, fore reef (seaward), shallow open marine and deep open marine settings. The petrographic analyses indicate that the Sarvak Formation carbonates have undergone a complex diagenetic history which includes compaction, cementation, dissolution, dolomitization, neomorphism and fracturing. Cementation and compaction reduced porosity, which led to low permeability and poor reservoir quality. Dissolution, dolomitization and fracturing diagenesis processes improved reservoir quality. The dissolution process generated secondary porosity consisting of vuggy and moldic types. While this has had an important effect on increasing porosity, the most important factor in the development of the reservoir has been fracturing.\u0000\u0000In lagoonal deposits, a single unit was distinguished with moldic and vuggy porosities. In shoal/reef deposits, two units were distinguished in terms of dissolution and grain frequency. In shallow open-marine deposits, two units were identified with different degrees of fracturing and dolomitization; while deep open-marine deposits were characterized by a third unit in terms of stylolitization and dolomitization. Consequently, the shoal/reef deposits with rudist grainstone and rudstone textures and interparticle and moldic porosities had the best reservoir quality. The key challenge in this reservoir analysis was to predict the vertical distribution of petrophysical properties to improve reservoir characterization. This research improved our understanding of geologic controls on the reservoir performance.","PeriodicalId":275861,"journal":{"name":"GeoArabia, Journal of the Middle East Petroleum Geosciences","volume":"33 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2010-03-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129092286","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Structures of the Kirkuk Embayment, Northern Iraq; Foreland Structures Or Zagros Fold Belt Structures?","authors":"W. Kent","doi":"10.3997/2214-4609-pdb.248.203","DOIUrl":"https://doi.org/10.3997/2214-4609-pdb.248.203","url":null,"abstract":"Several anticlines in northern Iraq and Syria have been studied through the construction of balanced and restored cross sections. Based upon structural analysis, each of the studied anticlines is a fault-propagation fold that developed due to Zagros-related, recent inversion of much older normal faults. Studies on the Iranian part of the Zagros Fold Belt have suggested that the regional variation in the character of the fold belt is related to weak detachment surfaces in the stratigraphic section, primarily the decollement developed near the top of the Hormuz Salt where the salt is present. No evidence for Hormuz Salt has been found within the Kirkuk Embayment, and although detachment surfaces contribute the area’s structural character, the prominent folds seem to originate mainly from basement involved faults. \u0000\u0000Two distinct inversion structural trends exist: E-W system and a NW system of inverted grabens. In Syria, several of the faults associated with the EW-trending system cut the basement on seismic data and have stratigraphic relationships indicating that their displacement originated in the Neoproterozoic. In Iraq, the thicker sedimentary section did not allow the deep parts of the fault systems to be imaged on the available seismic. While the NW fault system of inverted normal faults could be linked to the Zagros Orogen by a decollement surface in the sedimentary section, regional relationships and potential-field data suggest that this trend also is basement involved and has a Neoproterozoic origin.","PeriodicalId":275861,"journal":{"name":"GeoArabia, Journal of the Middle East Petroleum Geosciences","volume":"31 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2010-03-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"132662874","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Reactive transport models of structurally controlled hydrothermal dolomite: Implications for Middle East carbonate reservoirs. 9th Middle East Geosciences Conference, GEO 2010.","authors":"G. Jones","doi":"10.3997/2214-4609-PDB.248.463","DOIUrl":"https://doi.org/10.3997/2214-4609-PDB.248.463","url":null,"abstract":"Hydrothermal dolomitization is present in several Middle East carbonate reservoirs including Ghawar, the North Field and South Pars. Structurally controlled hydrothermal dolomitization describes the replacement of limestone with dolomite and/or the precipitation of dolomite cement and associated MVT minerals (anhydrite, sulfides, quartz and fluorite) as a consequence of subsurface brines that ascend upwards through fault and fracture systems. This fluid rock interaction in the burial environment has the potential to both improve and/or degrade reservoir quality depending on the properties of the host rock, fluid composition, timing of fluid flow and spatial position relative to structure.\u0000\u0000A reactive transport model (TOUGHREACT) that couples fluid flow with chemical reactions, was used to simulate hydrothermal dolomitization. Specifically we investigated the sensitivity of hydrothermal dolomite to: fault permeability/flow rates of ascending fluids, reservoir heterogeneity (alternating high and low permeability strata), temperature of host rock and ascending fluids (including their relative temperature difference), fault spacing/multiple fault scenarios, fault vertical separation and strata juxtaposition, episodic versus continuous brine injection and subsurface brine composition (in particular, Na-Cl versus Ca-Cl brines).\u0000\u0000Results from 2-D and 3-D models suggest that diagenetic modification and evolution of petrophysical properties in response to hydrothermal dolomitization are a complex function of the hydrodynamics and fluid chemistry. Variations in fault and matrix permeability strongly control the spatial patterns of diagenesis. Brine chemistry of both the host rock and the ascending fluids affect the extent and distribution of dolomitization. Na-Cl brines produce more dolomite than Ca-Cl brines because of higher Mg/Ca ratios but this result is salinity and temperature dependent. Hanging wall fault blocks are preferentially dolomitized. Depending on their permeability, relay zones between faults may remain undolomitized. For the systems simulated, hydrothermal dolomitization enhances matrix porosity and permeability but fault zones begin to seal due to the precipitation of anhydrite and dolomite cement. Breccia, vugs and fracture pore types that are commonly observed in hydrothermal dolomites are beyond current simulation capability. Thus predictions of reservoir quality from reactive transport models may be less useful than predictions of hydrothermal dolomite geobody dimensions.","PeriodicalId":275861,"journal":{"name":"GeoArabia, Journal of the Middle East Petroleum Geosciences","volume":"47 2 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2010-03-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122809918","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Regional issues in Jurassic pore systems: Echinoderms, syntaxial overgrowth cements and a fifth porositon. 9th Middle East Geosciences Conference, GEO 2010.","authors":"E. A. Clerke","doi":"10.3997/2214-4609-PDB.248.266","DOIUrl":"https://doi.org/10.3997/2214-4609-PDB.248.266","url":null,"abstract":"Regional and well-established geological and diagenetic processes are re-examined in Jurassic carbonate reservoirs using the large amount of quantitative mercury injection capillary pressure (MICP) pore system data acquired by Saudi Aramco in the last eight years. An extensive Berri Field dataset included petrographic data and MICP pore system data obtained by Thomeer analysis. The Berri data from four Jurassic carbonate reservoirs is compared to other data, and specifically the Ghawar Rosetta Stone data using a regional depositional context. The anticipated increase of Jurassic carbonate-rim cement to the north of Ghawar is evident. Much more important from a pore system perspective are the amounts of syntaxial overgrowth cement and the correlative increase of echinoderms and foraminifera in the Hadriya and Fadhili. These latter increases necessitate a fifth porositon (F-ESO), an additional maximum pore-throat diameter mode in the Hadriya and Fadhili pore system models, as compared to the four porositions that describe the pore systems of the Ghawar Arab D limestone and the Berri Arab and Hanifa reservoirs. Review of the Abqaiq Field petrographic and MICP data of Ross et al. (1995) provide independent support for the four porositons of Clerke et al. (2008) and also indicate the presence of a fifth (F-ESO) porositon in the Abqaiq Arab D. \u0000\u0000The pore system effect of the predicted and present carbonate rim cements is imperceptible. Echinoderm and foraminifera are very abundant in the Berri Fadhili and show a steady decrease in abundance upward through the Berri Jurassic section, that is, the Fadhili, Hadriya, Hanifa and the Arab. Echinoderm abundance is closely linked to marine salinities and high magnesium calcite. Quantitative determinations of echinoderm and foraminifera abundance are shown to be correlative to and useful as a predictor of the pore destructive syntaxial overgrowth cement. Regional models of reservoir quality distribution could potentially be improved using maps of high precision Ca/Mg ratio relating to the high magnesium calcite of echinoderms and syntaxial overgrowth cements and maps of echinoderm abundances and habitats. These regional maps could relate broadly and inversely to reservoir quality and depositional salinity.","PeriodicalId":275861,"journal":{"name":"GeoArabia, Journal of the Middle East Petroleum Geosciences","volume":"249 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2010-03-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114937204","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"FMI sedimentological interpretation, Western Desert, Egypt: An approach for high-resolution facies reservoir anatomy. 9th Middle East Geosciences Conference, GEO 2010.","authors":"E. Haddad","doi":"10.3997/2214-4609-pdb.248.073","DOIUrl":"https://doi.org/10.3997/2214-4609-pdb.248.073","url":null,"abstract":"The Bahariya Formation in the Western Desert is one of the major complex oil-bearing reservoirs in Egypt. Many discoveries have revealed the high oil potential in this formation. Detailed sedimentological interpretation was performed over the imaged highly complicated and inconsistent reservoir interval for Abu Roash “G” Member and Bahariya Formation in two drilled wells. Twenty lithofacies types were defined from the images of the two investigated wells. Individual lithofacies were defined based on detailed description of sedimentary structures from the image logs. The sand lithofacies of the Bahariya Formation and dolomite of Abu Roash “G” Member were assigned pay values. The identified electrofacies are calibrated with the cored intervals in one of the two wells.\u0000\u0000The Bahariya Formation in the studied two wells is interpreted as a tidal flat deposit and characterized by the following subenvironments: barrier bars, tidal channel and tidal flat muds. The Abu Roash “G” Member is considered as a subtidal carbonate and characterized by the presence of frequent secondary dolomite. Correlation is based mainly on the data gained from formation micro imager (FMI) sedimentological facies analysis and interpretation has been carried out to throw light on the lateral facies changes and consequently to solve many problems related to the reservoir complexity. The missing of some facies associations confirms the presence of faulting.","PeriodicalId":275861,"journal":{"name":"GeoArabia, Journal of the Middle East Petroleum Geosciences","volume":"105 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"1900-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"117349979","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Fluid status and saturation assessment in low-resistivity-pay carbonate reservoir using core scale petrophysical and resistivity modelling. 9th Middle East Geosciences Conference, GEO 2010.","authors":"F. Umbhauer","doi":"10.3997/2214-4609-pdb.248.430","DOIUrl":"https://doi.org/10.3997/2214-4609-pdb.248.430","url":null,"abstract":"Fluid status definition for completion strategy, or reliable saturation evaluation for hydrocarbon-in-place and reserves estimation in heterogeneous carbonates reservoirs, based on wireline resistivity logs, is often uncertain as these reservoirs often deviate from Archie’s Law. This can be explained by small-scale heterogeneities (patchy macroporous oil zones embedded in a microporous matrix), which can generate an excess of conductivity (electrical bypass through water-saturated microporous connected path). Applying Archie’s Law with the standard m and n = 2 values in such cases may lead to erroneous water-saturation computation, with serious consequences on fluid status, completion strategy and project economics.\u0000\u0000A methodology has been developed to tackle this problem by: (1) modelling reservoir heterogeneity at core scale using commercial geomodelling software, providing a reference oil volume calibrated by core petrophysical data (CT scan 3-D imaging, minipermeameter, porosity, permeability, capillary pressure); and (2) checking the accuracy of the model through forward modelling using a research 2-D resistivity modelling software that simulates the invasion process, by comparison with the acquired wireline resistivity logs response. \u0000\u0000This methodology was applied to a vuggy interval (“leopard-skin texture”) of a carbonate reservoir of Paleocene age, in the Sirte Basin, onshore Libya. The water saturation derived from resistivity logs interpretation with standards Archie’s parameters reached 77%, not consistent with drill stem tests (DST) production watercut values. Core-scale model provides an average saturation of 51%, which allows reproducing field watercuts. The forward 2-D resistivity modelling based on this model reproduced the acquired wireline laterolog curves and derived true resistivity profile, after adjustment of water salinity, consistent with regional data. \u0000\u0000In the absence of any nuclear magnetic resonance (NMR) or SIGMA log acquisitions, low-resistivity pay intervals in this reservoir have been successfully characterized. This was possible because the complete coring and testing program permitted a good calibration of petrophysical and electrical properties, an accurate modelling of reservoir heterogeneities, and a successful core-log upscaling process. Providing equivalent zones could be diagnosed through well data (log imagery) and geological knowledge (correlations) along uncored well sections, resistivity-derived saturation can be corrected thus leading to effective decisions for completion strategy.","PeriodicalId":275861,"journal":{"name":"GeoArabia, Journal of the Middle East Petroleum Geosciences","volume":"10 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"1900-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129610615","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}