Geological control factors of micro oil distribution in tight reservoirs

Understanding the oil distribution characteristics in unconventional tight reservoirs is crucial for hydrocarbon evaluation and oil/gas extraction from such reservoirs. Previous studies on tight oil distribution characteristics are mostly concerned with the basin scale. Based on Lucaogou core samples, geochemical approaches including Soxhlet extraction, total organic carbon (TOC), and Rock-Eval are combined with reservoir physical approaches including mercury injection capillary pressure (MICP) and porosity-permeability analysis, to quantitatively evaluate oil distribution of tight reservoirs on micro scale. The emphasis is to identify the key geological control factors of micro oil distribution in such tight reservoirs. Dolomicrites and non-detrital mudstones have excellent hydrocarbon generation capacity while detritus-containing dolomites, siltstones, and silty mudstones have higher porosity and oil content, and coarser pore throat radius. Oil content is mainly controlled by porosity, pore throat radius, and hydrocarbon generation capacity. Porosity is positively correlated with oil content in almost all samples including various lithologies, indicating that it is a primary constraint for providing storage space. Pore throat radius is also an important factor, as oil migration is inhibited by the capillary pressure which must be overcome. If the reservoir rock with suitable porosity has no hydrocarbon generation capacity, pore throat radius will be decisive. As tight reservoirs are generally characterized by widely distributed nanoscale pore throats and high capillary pressure, hydrocarbon generation capacity plays an important role in reservoir rocks with suitable porosity and fine pore throats. Because such reservoir rocks cannot be charged completely. The positive correlation between hydrocarbon generation capacity and oil content in three types of high porosity lithologies (detritus-containing dolomites, siltstones, and silty mudstones) supports this assertion.     

Experimental investigations on the geometry and connectivity of pore space in organic-rich Wufeng and Longmaxi shales

The nano-scale pore systems of organic-rich shale reservoirs were investigated from Upper Ordovician Wufeng and Lower Silurian Longmaxi Formations in southeast Sichuan Basin. These two formations are the most important target plays of shale gas development in China. The purpose of this article is to assess the geometry and connectivity of multi-scale pore systems, and to reveal the nature and complexity of pore structure for these over-mature gas shales. To achieve these objective, total organic carbon, mineralogy, image analyses by focused ion beam-SEM, low pressure nitrogen adsorption, mercury injection capillary pressure (MICP) and spontaneous fluid [deionized (DI) water and n-decane] imbibition were performed.Most of the visible pores from SEM work in Wufeng and Longmaxi shales are within nm- and μm-size regimes and belong to organic matter (OM) pores. The shapes of OM pore in Longmaxi samples are elliptical, bubble-like, irregular or rounded. Wufeng pores are mainly irregular, linear and faveolated, even though two shales have small depth difference, as well as similar thermal maturity, kerogen type and TOC content. Nano-scale pores in Longmaxi are mainly associated with narrow platelike or slitlike pores with pore size of 3–50 nm; while inkbottle pores are dominant in Wufeng samples and over 88% of the pore volume is contributed by pores with diameter <20 nm. Overall, porosity, pore volume and surface area values from Wufeng samples are much higher than those in Longmaxi, which is mainly correlated with the different TOC contents and mineral compositions. MICP tests show that a total of 5 inflection points (indicative of different connected pore networks) are identified in all pressure regions for Longmaxi, while only 2 for Wufeng in high pressure region with the associated permeability at nano-darcy range. Imbibition curves of n-decane are divided into three stages: the initial stage (Stage Ⅰ), linear imbibition stage (Stage Ⅱ) and late imbibition stage (Stage Ⅲ), and the slopes of linear imbibition stage are around 0.5, suggesting well-connected pore spaces for n-decane. In contrast, imbibition curves for DI water are divided in two stages with linear slopes of between 0.25 and 0.5, indicating moderately-connected pore networks for the movement of DI water. This is consistent with the mixed-wet nature of these shales, with observed weak wettability for hydrophilic, while complete wetting for hydrophobic fluids.     

Pore structure characteristics of tight sandstones in the northern Songliao Basin,China

Understanding the pore structure characteristics of tight gas sandstones is the primary purpose of reservoir evaluation and efforts to characterize tight gas transport and storage mechanisms and their controls. Due to the various pore types and multi-scale pore sizes in tight reservoirs, it is essential to combine several techniques to characterize pore structure. Scanning electron microscopy (SEM), nitrogen gas adsorption (N₂GA), mercury intrusion porosimetry (MIP) and nuclear magnetic resonance (NMR) were conducted on tight sandstones from the Lower Cretaceous Shahezi Formation in the northern Songliao Basin to investigate pore structure characteristics systematically (e.g., type and size distribution of pores) and to establish how significant porosity and permeability are for different pore types. The studied tight sandstones are composed of intergranular pores, dissolution pores and intercrystalline pores. The integration of N₂GA and NMR can be used as an efficient method to uncover full pore size distribution (PSD) of tight sandstones, with pore sizes ranging from 2 nm to dozens of microns. The full PSDs indicate that the pore sizes of tight sandstones are primarily distributed within 1.0 μm. With an increase in porosity and permeability, pores with larger sizes contribute more to porosity. Intercrystalline pores and intergranular/dissolution pores can be clearly distinguished on the basis of mercury intrusion and surface fractal. The relative contribution of intercrystalline pores to porosity ranges from 58.43% to 91.74% with an average of 79.74%. The intercrystalline pores are the primary contributor to pore space, whereas intergranular/dissolution pores make a considerably greater contribution to permeability. A specific quantity of intergranular/dissolution pores is the key to producing high porosity and permeability in tight sandstone reservoirs. The new two permeability estimation models show an applicable estimation of permeability with R² values of 0.955 and 0.962 for models using D_max (pore diameter corresponding to displacement pressure) and D_f (pore diameter at inflection point), respectively. These results indicate that both D_max and D_f are key factors in determining permeability.     

东海陆架盆地N气田花港组储层特征及分类评价

东海陆架盆地西湖凹陷古近系花港组储层为典型的低孔、低渗储层.基于大量岩心物性、粒度、薄片、压汞等资料,对N气田目的层储层岩性、物性和孔隙结构特征进行精细评价.结果表明:N气田花港组储层岩性以细砂岩为主,矿物成分构成稳定,以石英为主,黏土含量低,岩性较纯;随着埋藏变深,孔隙变差,粒间孔减少,溶蚀孔增加,孔喉半径减小,连通...     

Permeability in Rotliegend gas sandstones to gas and brine as predicted from NMR,mercury injection and image analysis

Permeability characterisation of low permeability, clay-rich gas sandstones is part of production forecasting and reservoir management. The physically based Kozeny (1927) equation linking permeability with porosity and pore size is derived for a porous medium with a homogeneous pore size, whereas the pore sizes in tight sandstones can range from nm to μm. Nuclear magnetic resonance (NMR) transverse relaxation was used to estimate a pore size distribution for 63 samples of Rotliegend sandstone. The surface relaxation parameter required to relate NMR to pore size is estimated by combination of NMR and mercury injection data. To estimate which pores control permeability to gas, gas permeability was calculated for each pore size increment by using the Kozeny equation. Permeability to brine is modelled by assuming a bound water layer on the mineral pore interface. The measured brine permeabilities are lower than predicted based on bound water alone for these illite rich samples. Based on the fibrous textures of illite as visible in electron microscopy we speculate that these may contribute to a lower brine permeability.     

How does the pore-throat size control the reservoir quality and oiliness of tight sandstones? The case of the Lower Cretaceous Quantou Formation in the southern Songliao Basin,China

Pore-throat size is a very crucial factor controlling the reservoir quality and oiliness of tight sandstones, which primarily affects rock-properties such as permeability and drainage capillary pressure. However, the wide range of size makes it difficult to understand their distribution characteristics as well as the specific controls on reservoir quality and oiliness. In order to better understand about pore-throat size distribution, petrographic, scanning electron microscopy (SEM), pressure-controlled mercury injection (PMI), rate-controlled mercury injection (RMI), quantitative grain fluorescence (QGF) and environmental scanning electron microscopy (ESEM) investigations under laboratory pressure conditions were performed on a suite of tight reservoir from the fourth member of the Lower Cretaceous Quantou Formation (K₁q₄) in the southern Songliao Basin, China. The sandstones in this study showed different types of pore structures: intergranular pores, dissolution pores, pores within clay aggregates and even some pores related to micro fractures. The pore-throat sizes vary from nano- to micro-scale. The PMI technique views the pore-throat size ranging from 0.001 μm to 63 μm and revealed that the pore-throats with radius larger than 1.0 μm are rare and the pore-throat size distribution curves show evident fluctuations. RMI measurements indicated that the pore size distribution characteristics of the samples with different porosity and permeability values look similar. The throat size and pore throat radius ratio distribution curves had however significant differences. The overall pore-throat size distribution of the K₁q₄ tight sandstones was obtained with the combination of the PMI and RMI methods. The permeability is mainly contributed by a small part of larger pore-throats (less than 30%) and the ratio of the smaller pore-throats in the samples increases with decreasing permeability. Although smaller pore-throats have negligible contribution on reservoir flow potential, they are very significant for the reservoir storage capacity. The pore-throats with average radius larger than 1.0 μm mainly exist in reservoirs with permeability higher than 0.1mD. When the permeability is lower than 0.1mD, the sandstones are mainly dominated by pore-throats with average radius from 0.1 μm to 1.0 μm. The ratio of different sized pore-throats controls the permeability of the tight sandstone reservoirs in different ways. We suggest that splitting or organizing key parameters defining permeability systematically into different classes or functions can enhance the ability of formulating predictive models about permeability in tight sandstone reservoirs. The PMI combined with QGF analyses indicate that oil emplacement mainly occurred in the pore-throats with radius larger than about 0.25–0.3 μm. This result is supported by the remnant oil micro-occurrence evidence observed by SEM and ESEM.     

利用压汞资料进行低渗储层孔隙结构特征分析——以Wll-7油田流沙港组三段储层为例

储层孔隙结构是影响低渗储层微观孔隙内流体运移与聚集的主要因素,决定了储层的优劣。以w11－7油田流沙港组三段储层为例,应用压汞资料定性与定量研究储层孔隙结构特征。研究结果表明,孔隙结构分为三类,总体上具有“喉道细、分选差、连通性差”的特点,这种较差的孔隙结构发育特征是造成储层呈低渗一特低渗的核心因素。在此基础上应用多元判别方法优选出排驱压力、中值压力、最大孔喉半径、孔喉半径均值、分选系数五类孔隙结构分类评价参数,并结合常规物性将储层分为三类,其中Ⅱ、Ⅲ类是广为发育的储层。     

琼东南盆地深水区中央峡谷黄流组储层特征及主控因素

在利用钻井和岩心资料基础上,结合铸体薄片、常规物性、压汞实验等分析测试手段,对琼东南盆地深水区中央峡谷黄流组储层特征及其影响因素进行了分析。研究表明,中央峡谷黄流组砂岩以岩屑石英砂岩为主,砂岩粒级较细且分选好,成熟度较高。原生粒间孔为主要孔隙类型,孔隙结构普遍为中孔细喉型。储层物性总体表现为中孔-特高孔、中渗-特高渗的特征。沉积微相和成岩作用是影响黄流组储层物性的主要因素,深水浊流沉积的水道砂岩是发育优质储层的前提,同时中央峡谷特殊的水深和温压条件是影响储层成岩作用的重要因素。海水深度大,而实际地层埋深浅,储层总体处于低温常压环境中,以致成岩作用程度普遍不强,但中央峡谷黄流组储层物性的内在差异仍主要受控于压实作用,中央峡谷自西向东,水深增加,实际地层埋深变浅,压实作用减弱,储层孔隙度和渗透率较好,总体上峡谷东部气层含气饱和度也较西部高。     

3D Pore-network quantitative analysis in deformed carbonate grainstones

This study consists of a three-dimensional (3D) assessment of the pore network properties (i.e., porosity, pore connectivity, specific surface area) in deformed carbonate grainstones cropping out in Sicily and Abruzzo regions (Italy). Previous studies, including microphotography, mercury injection analysis, and in-situ air permeameter measurements, have reported permeability differences (in the range of two-to-three orders of magnitude) between the carbonate grainstones exposed in Sicily and Abruzzo, that cannot be explained by only considering the differences of porosity. In this study, the pore network properties of suitable rock samples were studied by quantitative analysis of X-ray micro-CT images using both synchrotron and microfocus sources. On the basis of the results, inferences about the control of pore network properties on permeability were made for both host rock and deformation bands. In the host rocks, high values of connectivity seem to be associated with high values of permeability, whereas higher values of the specific surface area seem to correspond to lower permeability. Within the deformation bands (DBs), both porosity and pore connectivity are reduced except for local solution-enlarged stylolites and fractures (slip surfaces) preferentially connected parallel to the DB.     

The impact of composition on pore throat size and permeability in high maturity shales: Middle and Upper Devonian Horn River Group,northeastern British Columbia,Canada

Shale reservoirs of the Middle and Upper Devonian Horn River Group provide an opportunity to study the influence of rock composition on permeability and pore throat size distribution in high maturity formations. Sedimentological, geochemical and petrophysical analyses reveal relationships between rock composition, pore throat size and matrix permeability.In our sample set, measured matrix permeability ranges between 1.69 and 42.81 nanodarcies and increases with increasing porosity. Total organic carbon (TOC) content positively correlates to permeability and exerts a stronger control on permeability than inorganic composition. A positive correlation between silica content and permeability, and abundant interparticle pores between quartz crystals, suggests that quartz may be another factor enhancing the permeability. Pore throat size distributions are strongly related to TOC content. In organic rich samples, the dominant pore throat size is less than 10 nm, whereas in organic lean samples, pore throat size distribution is dominantly greater than 20 nm. SEM images suggest that in organic rich samples, organic matter pores are the dominant pore type, whereas in quartz rich samples, the dominant type is interparticle pores between quartz grains. In clay rich and carbonate rich samples, the dominant pore type is intraparticle pores, which are fewer and smaller in size.High permeability shales are associated with specific depositional facies. Massive and pyritic mudstones, rich in TOC and quartz, have comparatively high permeability. Laminated mudstone, bioturbated mudstone and carbonate facies, which are relatively enriched in clay or carbonate, have fairly low permeability.     

西湖凹陷KX构造平湖组储层特征及主控因素研究

西湖凹陷KX构造始新统平湖组是重要产气层系.利用大量薄片、岩心和分析化验资料,对该平湖组储集层进行了详细的岩石学特征、储层物性分析以及影响储层发育的主控因素的研究.结果表明,该套储层的岩石类型以长石岩屑质石英砂岩主,填隙物丰富、分选中等—好、成分成熟度低、磨圆程度高;孔隙类型以次生孔隙为主;喉道类型以片状、弯曲片状喉道为主;孔喉组合类型为中孔小喉、小孔小喉组合;储层物性较差,为低孔低渗储层;平湖组储层主要受潮汐改造的分流河道微相控制,压实作用、胶结作用、溶蚀作用和破裂作用等成岩作用是研究区储集层物性的主要控制因素.     

Experimental evaluation of reservoir quality in Mesozoic formations of the Perth Basin (Western Australia) by using a laboratory low field Nuclear Magnetic Resonance

Accurate porosity and permeability evaluation of rock formations is critical to estimate the quality and resource potential of a reservoir. In addition to directly measure the porosity and pore size distribution, low field Nuclear Magnetic Resonance (NMR) is able to measure the effective porosity and estimate the in-situ formation permeability, though its robustness is arguable and requires calibrations on cores with specific lithologies.The Mesozoic formations of the central Perth Basin (Western Australia) host hot sedimentary aquifers and recently became key targets for geothermal heat extraction. A collection of cores was retrieved from three wells intersecting these units. The characterisation of their flow properties complements the current evaluation of the Perth Basin by adding new data on effective porosity, pore size distribution, pore geometry and calibration of predictive models for the permeability according to a comprehensive facies classification scheme.This study highlights the consistency of the NMR approach when compared to conventional helium injection method. Most favourable lithologies for well production correspond to very coarse to fine sandstones of fluvial channel fill with porosities >15% and permeabilities >>1 mD. Similarly, these facies exhibit (i) the highest effective porosities, (ii) the highest pore space to pore throat ratio, and (iii) the lowest contribution of clay bound water. These aspects confirm the importance of clay occurrence in the assessment of the flow efficiency of a formation.The Yarragadee Formation presents the best reservoir quality regarding its porosity and permeability, even though high discrepancies occur locally owing to the great variability of lithofacies encountered. The scattered values observed for the Lesueur Sandstone are likely to be due to the basin architecture and fault system which generate different mechanical compaction and secondary cementation. Given an adequate facies analysis, the NMR method represents a powerful tool to estimate the flow efficiency of a reservoir.     

Controls on reservoir heterogeneity of tight sand oil reservoirs in Upper Triassic Yanchang Formation in Longdong Area,southwest Ordos Basin,China: Implications for reservoir quality prediction and oil accumulation

Compared to conventional reservoirs, pore structure and diagenetic alterations of unconventional tight sand oil reservoirs are highly heterogeneous. The Upper Triassic Yanchang Formation is a major tight-oil-bearing formation in the Ordos Basin, providing an opportunity to study the factors that control reservoir heterogeneity and the heterogeneity of oil accumulation in tight oil sandstones.The Chang 8 tight oil sandstone in the study area is comprised of fine-to medium-grained, moderately to well-sorted lithic arkose and feldspathic litharenite. The reservoir quality is extremely heterogeneous due to large heterogeneities in the depositional facies, pore structures and diagenetic alterations. Small throat size is believed to be responsible for the ultra-low permeability in tight oil reservoirs. Most reservoirs with good reservoir quality, larger pore-throat size, lower pore-throat radius ratio and well pore connectivity were deposited in high-energy environments, such as distributary channels and mouth bars. For a given depositional facies, reservoir quality varies with the bedding structures. Massive- or parallel-bedded sandstones are more favorable for the development of porosity and permeability sweet zones for oil charging and accumulation than cross-bedded sandstones.Authigenic chlorite rim cementation and dissolution of unstable detrital grains are two major diagenetic processes that preserve porosity and permeability sweet zones in oil-bearing intervals. Nevertheless, chlorite rims cannot effectively preserve porosity-permeability when the chlorite content is greater than a threshold value of 7%, and compaction played a minor role in porosity destruction in the situation. Intensive cementation of pore-lining chlorites significantly reduces reservoir permeability by obstructing the pore-throats and reducing their connectivity. Stratigraphically, sandstones within 1 m from adjacent sandstone-mudstone contacts are usually tightly cemented (carbonate cement > 10%) with low porosity and permeability (lower than 10% and 0.1 mD, respectively). The carbonate cement most likely originates from external sources, probably derived from the surrounding mudstone. Most late carbonate cements filled the previously dissolved intra-feldspar pores and the residual intergranular pores, and finally formed the tight reservoirs.The petrophysical properties significantly control the fluid flow capability and the oil charging/accumulation capability of the Chang 8 tight sandstones. Oil layers usually have oil saturation greater than 40%. A pore-throat radius of less than 0.4 μm is not effective for producible oil to flow, and the cut off of porosity and permeability for the net pay are 7% and 0.1 mD, respectively.     

The numerical study of wave-induced pore water pressure response in highly permeable seabed

The coupling numerical model of wave interaction with porous medium is used to study waveinduced pore water pressure in high permeability seabed.In the model,the wave field solver is based on the two dimensional Reynolds-averaged Navier-Stokes(RANS) equations with a k-ε closure,and Forchheimer equations are adopted for flow within the porous media.By introducing a Velocity-Pressure Correction equation for the wave flow and porous flow,a highly efficient coupling between the two flows is implemented.The numerical tests are conducted to study the effects of seabed thickness,porosity,particle size and intrinsic permeability coefficient on regular wave and solitary wave-induced pore water pressure response.The results indicate that,as compared with regular wave-induced,solitary wave-induced pore water pressure has larger values and stronger action on seabed with different parameters.The results also clearly show the flow characteristics of pore water flow within seabed and water wave flow on seabed.The maximum pore water flow velocities within seabed under solitary wave action are higher than those under regular wave action.     

苏北盆地白垩系赤山组沉积与储层特征及研究意义

通过石油钻井及野外地质露头等资料,利用薄片资料、扫描电镜资料、岩屑录井资料、孔渗资料及压汞实验分析,对苏北盆地白垩系赤山组沙丘沉积特征、储层岩石学特征、储层孔隙、储层物性等进行了系统的研究。结果表明,沙丘作为沙漠沉积中最重要的亚相类型,以风成沉积为显著特征,具有沉积厚度大、成熟度高、电性特征明显等特点。溶蚀作用是孔隙的主要形成作用,原生孔隙很少,次生孔隙极其发育,是油气的良好储集层。沙丘沉积的研究对于油气的勘探开发具有重要的现实意义。     

渤海海域Z油田水驱开发储层物性变化规律

为研究海上稠油砂岩油藏水驱开发储层物性变化规律,以渤海海域Z油田为目标,利用多口密闭取心井资料,结合油田生产实际,从储层的黏土矿物、孔隙结构、储集孔渗及渗流特征等方面系统开展了水驱开发前后储层物性变化规律及机理研究.结果表明,经长期水驱开发,储层中黏土矿物总量呈减少趋势,其中高岭石含量降低,伊/蒙混层含量增加;岩石平均...     

Evolution of petrophysical properties of oil shales during high-temperature compaction tests: Implications for petroleum expulsion

The transport properties of Permian to Miocene oil shales (Torbanite, Posidonia, Messel, Himmetoglu, and Condor) were studied using petrophysical and geochemical techniques. The aims of this study were to assess permeability of oil shales, evaluate the evolution of porosity, specific surface area and intergranular permeability during high temperature compaction tests and to verify the suitability of intergranular permeability for petroleum expulsion. Measured permeability coefficients for two samples were 0.72 × 10⁻²¹ m² for the Eocene Messel shale and 2.63 × 10⁻²¹ m² for the Lower Jurassic Posidonia shale from S. Germany, respectively. BET specific surface areas of the original samples ranged from 0.7 to 10.6 m²/g and decreased after compaction to values from 0.3 to 3.7 m²/g. Initial porosity values ranged from 7.6 to 20.1 % for pre-deformation and from 9.99 to 20.7 % for post-deformation samples. Porosity increased during the high-temperature compaction experiments due to petroleum generation and expulsion. Permeability coefficients estimated using the Kozeny–Carman equation varied from 6.97 × 10⁻²⁴ m² to 5.22 × 10⁻²¹ m² for pre-deformation and from 0.2 × 10⁻²¹ m² to 4.8 × 10⁻²¹ m² for post-deformation samples reflecting the evolution of their porosity and BET specific surface areas. Measured and calculated permeability were similar for the Messel shale whereas calculated permeability was two orders of magnitude lower for the Posidonia shale from S. Germany. Petroleum expulsion efficiencies under the experimental conditions ranged from 38.6% for the Torbanite to 96.2% for the Posidonia shale from S. Germany. They showed strong positive correlation with the petroleum generation index (R² = 0.91) and poor correlations with porosity (R² = 0.46), average pore throat diameters (R² = 0.22), and compaction (R² = 0.02). Estimated minimum pore-system saturations for petroleum expulsion during the experiments were 12% for the Torbanite and 30% for the Posidonia shale from N. Germany. Pore-system saturation determines whether expulsion occurs mainly through matrix or fracture permeability. For samples with saturation levels above 20%, fracture permeability dominated during the experiments. Evidence based on the measured permeability coefficients, expulsion flow rates, consideration of capillary displacement during generation-related pore invasion and the existence of transport porosity suggests that fracture permeability is the principal avenue of petroleum expulsion from source rocks. This conclusion is supported by microscopic observations.     

The influence of particle morphology on microbially induced CaCO3 clogging in granular media

Abstract

Sporosarcina pasteurii (ATCC 11859) is a nitrogen-circulating bacterium capable of precipitating calcium carbonate given a calcium source and urea. This microbially induced carbonate precipitation (MICP) is able to infill inter-granular porosity and act as a biological clogging agent, thus having a wide potential application in strengthening coastal foundations, preventing erosion by seas and rivers and in reducing sand liquefaction potential in coastal areas. A successful MICP application requires the understanding of the primary parameters that influence the microbially mediated process to achieve its engineering goals, such as injection scheme, chemical concentrations, retention times, and injection rates. However, the granular morphology has generally been oversimplified to ideal shape without enough consideration in previous studies. The following explores the critical micro-scale influence of particle morphology on mechanisms of microbially induced clogging. Spherical, non-spherical and angular particles were used as granular aggregates in permeating column experiments with the resulting permeability and calcium carbonate content of the treated aggregates examined. Microscopic examination (SEM) defines the features of the distribution of microbially precipitated calcium carbonate and the forms of clogging. The results show: (1) given a fixed duration of treatment, the calcium carbonate content for the spherical particle aggregate is significantly higher than that for near-spherical and angular particle aggregates; (2) for identical durations of treatment, the maximum permeability reduction occurs for angular particles (rather than for spherical particles with the highest carbonate content). This suggests that the microscopic distribution of calcium carbonate is significantly influenced by particle morphology, exerting a critical control in the effectiveness of clogging. SEM images indicate that the microbial calcium carbonate precipitates encapsulate the spherical particles as a near-uniform shell and occlude the pore space only by increasing the shell thickness. In contrast, the near-spherical and angular particles are only partially coated by a calcium carbonate film with scattered crystals of vaterite and calcite further clogging the void space. The polyhedral nature of the non-spherical particles tends to result in a slot-shaped pore structure which critically defines the hydraulic conductivity of the ensemble medium. As the microbial vaterite and calcite continue to accumulate on the particle surface, these slot-shaped pore structures become increasingly more tortuous – resulting in a noticeable reduction of permeability at a lower calcium carbonate content.     

Influence of hydrocarbon injection on the compaction by pressure-solution of a carbonate rock: An experimental study under triaxial stresses

The preservation of good petrophysical properties (high porosity/high permeability) at great depth in carbonate rocks may lead to the existence of a deeply buried reservoir (DBR), a target of interest for the oil industry. One of the key processes controlling diagenesis of the burial environment is Pressure Solution Creep (PSC), an efficient compaction process responsible for the evolution of porosity and permeability in many carbonate reservoirs. In this experimental study, we examine the effect of i) the presence of oil in the pore space and ii) its timing of injection on the PSC process and the petrophysical properties of a carbonate rock. The experiments were performed using a flow-through high-pressure cell, allowing the simulation of the pressure/stresses and temperature conditions of a DBR. Multi-disciplinary data (mechanical, chemical, petrographical and petrophysical) demonstrate that, without oil in the pore space, the main diagenetic process is the PSC, a process reducing by three the initial porosity but having no influence on intrinsic water permeability. An early injection of oil prior to water circulation causes the inhibition of PSC by the coating of the grains, leading to the preservation of porosity. Conversely, a late injection of oil does not preserve initial porosity. The dataset obtained from these experiments show the importance of the timing of oil charging in a reservoir in the preservation of initial porosity at great depth by the inhibition of PSC. However, the coating of grains by hydrocarbons may also inhibit further diagenetic processes leading to a creation of secondary porosity at depth.