Carbonate Reservoir Rocks Research Articles

Carbonate-Rock-Physics Issues

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper IPTC 13850, ’Carbonate-Rock Physics Issues,’ by Enru Liu, Michael A.Payne, Shiyu Xu, Gregor Baechle, and Christopher E. Harris, ExxonMobil Upstream Research, prepared for the 2009 International Petroleum Technology Conference, Doha, Qatar, 7-9 December. Limestone and dolomite reservoirs account for approximately half of oil and gas production worldwide, yet seismic responses in carbonate rocks are poorly understood. Development of a carbonate-rock-physics model is extremely difficult because the pore systems are more complex in carbonates than in clastics. In addition to pore types and shapes, other factors that need to be included in a physics-based rock model include lithology, grain shapes, multiphase-fluid and wetting effects, rock/fluid interactions (poroelasticity), stress effects, anisotropy, heterogeneity and scale effects, chemical changes to the framework, and corrections for environmental effects for logging conditions. The effect and validation of several of these factors are presented. Introduction Carbonates can have a variety of pore types, such as moldic, vuggy, interparticle, or intraparticle. The complex pore system creates significant scatter in the porosity/velocity relationship. Pore shape appears to be the dominant factor in carbonate-rock physics. Moldic, intraframe, and vuggy pores tend to be rounded and make the rock stronger (faster) than pores that are interparticle. Micropores (e.g., microcracks) tend to be flat and make the rock weaker. To characterize carbonate reservoir rocks effectively, it is critical to develop a rock-physics model that is capable of handling different pore types. Any rock-physics model should be calibrated and validated with controlled laboratory experiments, field measurements, and computational rock physics. Carbonate-Rock Physics Model An analytical-rock-physics model was selected rather than an empirical one because of the analytical model’s predictive power without the need to acquire considerable analog data and because it is physics based. Empirical rock-physics models often are used because of their simplicity in fitting a relationship between parameters. With an analytical model, once parameters that describe the physical controlling factors are determined, the model can be applied anywhere that the controlling parameters can be estimated. This method achieves better predictions and a deeper understanding of the subsurface than empirical models, with less data. Nonlinear physics-based inclusion models are attractive because they handle various factors that affect seismic response in an internally consistent manner.

Dynamical surface affinity of diphasic liquids as a probe of wettability of multimodal porous media

We introduce a method for estimating the wettability of rock/oil/brine systems using noninvasive in situ nuclear magnetic relaxation dispersion. This technique scans over a large range of applied magnetic fields and yields unique information about the extent to which a fluid is dynamically correlated with a solid rock surface. Unlike conventional transverse relaxation studies, this approach is a direct probe of the dynamical surface affinity of fluids. To quantify these features we introduce a microscopic dynamical surface affinity index which measures the dynamical correlation (i.e., the microscopic wettability) between the diffusive fluid and the fixed paramagnetic relaxation sources at the pore surfaces. We apply this method to carbonate reservoir rocks which are known to hold about two thirds of the world's oil reserves. Although this nondestructive method concerns here an application to rocks, it could be generalized as an in situ liquid/surface affinity indicator for any multimodal porous medium including porous biological media.

SHALLOW‐MARINE MICROPOROUS CARBONATE RESERVOIR ROCKS IN THE MIDDLE EAST: RELATIONSHIP WITH SEAWATER Mg/Ca RATIO AND EUSTATIC SEA LEVEL

The formation of shallow‐marine microporous carbonate reservoir rocks remains poorly understood in spite of their economic importance, particularly in the Middle East. In this paper, we investigate relationships between the stratigraphic occurrence of these carbonates in the Middle East and (i) the evolution of the Mg/Ca ratio in seawater; and (ii) cyclic variations in relative sea‐level.An inventory of carbonate formations in the Middle East was compiled for three geological time intervals characterised by different seawater chemistries: the Late Carboniferous to Triassic (aragonite seas); the Cretaceous (calcite seas); and the Cenozoic (transitional from calcite to aragonite seas). For each time interval, carbonate formations described as microporous have been listed.During the Cretaceous calcite sea, eleven microporous carbonate formations were deposited in the Middle East. However, no microporous carbonates were formed during the Late Carboniferous to Triassic, a time of aragonite seas. During the Cenozoic, four of the five microporous carbonate formations recorded were deposited before the transition from calcite to aragonite seas. Thus, these shallow‐marine microporous carbonates appear to have developed from precursor muds which were mainly composed of low‐Mg calcite crystals. Moreover, during the Cretaceous and the Cenozoic, microporous carbonate formations in the Middle East were generally associated with major transgressions and highstands of relative sea level.The relatively high stability of low‐Mg calcite muds may explain why shallow‐marine microporous carbonates formed during time intervals with calcite seas. In contrast to muds composed of aragonite or high‐Mg calcite crystals, the original microfabric (including intercrystalline microporosity) of low‐Mg calcite muds can partly survive moderate diagenesis.

Measurement of Acid Reaction Rates with the Rotating Disk Apparatus

Abstract The authors have published several papers on the rotating disk apparatus (RDA) in recent years. The RDA is used to measure acid reaction rates, reaction order and activation energy of acidizing fluids with carbonate reservoir rock. This paper summarizes the different ways that acid reaction rates are measured, the factors that affect the results and why this is important when modelling acid stimulation treatments in the field. In particular, experimental procedures used to obtain acid reaction rates vary widely and can produce very different results. These procedures are often not well-documented in the literature. The validity of different experimental procedures are carefully compared in this paper. In addition to experimental concerns, the reactivity of reservoir rock can also vary widely. It was recently reported that the reactivity of reservoir rock toward acid is strongly affected by mineralogy and by mineral impurities. In particular, clay impurities in calcite rock were found to reduce the dissolution rate by nearly an order of magnitude. Some calcite rocks with clay content as low as 1 wt% showed acid reactivity similar to that of 100 wt% dolomite. Acidizing additives such as polymers and corrosion inhibitors have been shown to significantly affect the way that acid reacts with the reservoir rock. Introduction The rotating disk instrument is widely used in the petroleum industry for kinetic studies of the reaction of acidic fluids and chelating agents with reactive rocks(1–11). This system allows the determination of rock dissolution rate, reaction rate constants, reaction order and diffusion coefficients(1, 12). Taylor et al.(13) examined the effects of acidizing additives on acid reaction rates of calcite and dolomite rock. These additives were quaternary amines, polymer, surfactant, mutual solvent, iron chelating agents and dissolved iron (III). Taylor et al.(14, 15) examined, in detail, the relationship between acid reaction rate and rock mineralogy for a deep, dolomitic gas reservoir. Their results showed that mineralogy significantly affected acid reaction rate, and that clay contents as low as 1 wt% could reduce the apparent reaction rate of limestone reservoir rock by up to a factor of 25. There has been significant variability in acid reaction rate data of reservoir rocks(11). These variations have often been attributed to activation energies lower than obtained for pure calcite or dolomite rock(11). However, several detailed studies have contradicted this claim(8, 16). Alkattan et al.(8) showed that the dissolution rates of calcite crystals, limestones and compressed calcite powders were the same within experimental error in the bulk solution pH range of ?1 to 3 at temperatures of 25, 50 and 80 °C. The limestones contained less than 1 vol% clays, but one type of limestone (St. Maximin) did contain 16 vol% quartz. This shows that the dissolution rates of pure forms of calcium carbonate are not significantly affected by different mineralogy. Herman and White(16) showed that dissolution rates of pure forms of dolomite are not significantly affected by mineralogy. The dissolution rates of dolomites in the form of a single crystal, microcrystalline sedimentary rock and coarse-grained marble in aqueous carbonate solutions were also found to be similar(16).

Artificial-Intelligence Technology Predicts Relative Permeability of Giant Carbonate Reservoirs

Summary Determination of relative permeability data is required for almost all calculations of fluid flow in petroleum reservoirs. Water/oil relative permeability data play important roles in characterizing the simultaneous two-phase flow in porous rocks and in predicting the performance of immiscible displacement processes in oil reservoirs. They are used, among other applications, for determining fluid distributions and residual saturations, predicting future reservoir performance, and estimating ultimate recovery. Undoubtedly, these data are considered probably the most valuable information required in reservoir-simulation studies. Estimates of relative permeability are generally obtained from laboratory experiments with reservoir-core samples. In the absence of the laboratory measurement of relative permeability data, developing empirical correlations for obtaining accurate estimates of relative permeability data showed limited success, and it proved difficult, especially for carbonate reservoir rocks. Artificial-neural-network (ANN) technology has proved successful and useful in solving complex structured and nonlinear problems. This paper presents a new modeling technology to predict accurately water/oil relative permeability using ANNs. The ANN models of relative permeability were developed using experimental data from waterflood-core-tests samples collected from carbonate reservoirs of giant Saudi Arabian oil fields. Three groups of data sets were used for training, verification, and testing the ANN models. Analysis of results of the testing data set shows excellent agreement with the experimental relative permeability data. In addition, error analyses show that the ANN models developed in this study outperform all published correlations. The benefits of this work include meeting the increased demand for conducting special core analysis (SCA), optimizing the number of laboratory measurements, integrating into reservoirsimulation and reservoir-management studies, and providing significant cost savings on extensive laboratory work and substantial required time.

ドロマイト化作用と貯留岩性状

Dolomite (dolostone) is a common carbonate rock in the geological records and is also a very important carbonate reservoir rock, which stock about 40% of global oil reserves. Most of the dolomites in the geological record are considered to be of replacement origin, although some were precipitated directly from pore-fluids. A variety of dolomitization models in different diagenetic environments are currently proposed for interpreting ancient dolomites: (1) evaporative dolomitization including sabkha and seepage-reflux models, (2) mixed-water dolomitization, (3) marine dolomitization, (4) burial dolomitization, (5) hydrothermal dolomitization. The dolomites formed by each dolomitization model have different geological, petrographical, mineralogical and geochemical features. Based on these features, we can, therefore, identify dolomitization models and diagenetic environments of ancient dolomites. A dolomite reservoir is often of as good quality as a limestone reservoir. Dolomitization affects carbonate reservoir characteristics, such as porosity and permeability, and, as a result, reservoir characteristics are significantly changed from those of primary carbonate rocks. The important factors associated with dolomitization and controlling the characteristics of carbonate reservoir rocks are: (1) increasing crystal size (2) decreasing porosity due to a net addition of dolomite, (3) developing moldic pores, (4) increasing resistance to compaction, and (5) increasing fractures. Dolomitization and diagenetic history of individual carbonate reservoirs differ from each other and result in the complexity of reservoir characteristics. It is, therefore, indispensable to understand the processes that formed each dolomite reservoir.

Subsurface characterization and geological monitoring of the CO 2 injection operation at Weyburn, Saskatchewan, Canada

Abstract The IEA Weyburn Carbon Dioxide (CO 2 ) Monitoring and Storage Project analysed the effects of a miscible CO 2 flood into a Lower Carboniferous carbonate reservoir rock at an onshore Canadian oilfield. Anthropogenic CO 2 is being injected as part of a commercial enhanced oil recovery operation. Much of the research performed in Europe as part of an international monitoring project was aimed at analysing the long-term migration pathways of CO 2 and the effects of CO 2 on the hydrochemical and mineralogical properties of the reservoir rock. The pre-CO 2 injection hydrochemical, hydrogeological and petrographical conditions in the reservoir were investigated in order to recognize changes caused by the CO 2 flood and to assess the long-term fate of the injected CO 2 . The Lower Carboniferous (Mississippian) aquifer has a salinity gradient in the Weyburn area, where flows are oriented SW–NE. Hydrogeological modelling indicates that dissolved CO 2 would migrate from Weyburn in an ENE direction at a rate of about 0.2 m/annum under the influence of regional groundwater flow. Baseline gas fluxes and CO 2 concentrations in groundwater were also investigated. The gas dissolved in the reservoir waters allowed potential transport pathways to be identified. Analysis of reservoir fluids proved that dissolved CO 2 and methane (CH 4 ) increased significantly in the injection area between 2002 and 2003. Most of the injected CO 2 exists in a supercritical state, lesser amounts are trapped in solution and there is little apparent mineral trapping. The CO 2 has already reacted with the reservoir rock sufficiently to mask some of the strontium isotope signature caused by 40 years of water flooding. Experimental studies of CO 2 –porewater–rock interactions in the Midale Marly Unit indicated slight dissolution of carbonate and silicate minerals, followed by relatively rapid saturation with respect to carbonate minerals. Carbon dioxide flooding experiments on similar rock samples demonstrated that porosity and gas permeability increased significantly through dissolution of calcite and dolomite. Several microseismic events were recorded over a six-month period and these are provisionally interpreted as being related to small fractures formed by injection-driven fluid migration within the reservoir, as well as other oilfield operations. Experimental studies on the overlying and underlying units show similar reaction processes; however secondary gypsum precipitation was also observed. Reaction experiments were conducted with CO 2 and borehole cements. The size and tensile strength of the cement blocks were unaffected, however their densities increased. Pre- and post-injection soil gas survey data are consistent with a shallow biological origin for the measured CO 2 in soil gases. Isotopic (δ 13 C) data values are higher than in the injected CO 2 , and confirm this interpretation. No evidence for leakage of the injected CO 2 to ground level has been detected. The long-term safety and performance of CO 2 storage was assessed by the construction of a features, events and processes (FEP) database that provides a comprehensive knowledge base for the geological storage of CO 2 .

Petroacoustics of carbonate reservoir rocks

Although more than half of hydrocarbon reserves are in carbonate reservoir rocks, little has been published concerning their petroacoustics (acoustics of rocks). One reason is that conventional measurement techniques (ultrasonic propagating waves, first-break picking for velocity, spectral ratio for attenuation) do not always perform adequately in carbonate rocks because of their heterogeneity. Frequently encountered problems include:

Identification of reservoir facies within a carbonate and mixed carbonate-siliciclastic sequence: Application of seismic stratigraphy, seismic attributes, and 3D visualization

The area of study is in the Cental Graben, between the Heera-Panna-Bassein Platform and the Eastern Homocline, within the Mumbai Basin off the west coast of India (Figure 1). The area is considered prospective because of its proximity to the Central Graben (a known hydrocarbon kitchen) and the presence of carbonate and sandstone reservoir rocks in adjoining areas to the southwest. In this part of the basin, sandstones in the Paleocene to Lower Eocene sequences and carbonates in the Middle to Upper Eocene sequences are dominant reservoir rocks. Earlier workers mapped several carbonate buildups in Middle to Upper Eocene sequences on the basis of 2D seismic data. A few exploratory wells were drilled to prove the envisaged strati-structural plays but most were dry, primarily caused by lack of reservoir or seals.

Study of Fractures and Vugs in Carbonate Reservoirs

A new technique of studying fractured and vuggy carbonate reservoirs is presented. It involves saturation of cubic cores (5 × 5 × 5 cm) with luminescent material (luminophore). Several examples of Russian carbonate reservoir rocks are given.

Application of microfocus computed tomography in carbonate reservoir characterization: Possibilities and limitations

Normally thin-section petrography, by which observations are made in two dimensions, forms the basis of sedimentpetrological reservoir appraisal studies. In reservoir characterization however, insight in the three-dimensional mineral and porosity distribution is necessary. In this study microfocus computed tomography (μCT), which is a non-destructive technique, has been used for 3D characterization of the mineral phases (i.e. calcite, dolomite, anhydrite) and porosity in carbonate reservoir rocks. In order to obtain quantitative information on density and atomic number of the scanned reservoir samples, as well as about their rock texture, a dual-energy scanning technique has been used. Additional beam artifact correction and a segmentation algorithm, focused on differentiating calcite, dolomite and anhydrite, have been implemented. To validate the developed methodology, thin sections of scanned samples of the Khuff Formation (Oman) have also been analyzed petrographically and compared to corresponding μCT sections and to the results of the dual-energy algorithms. Despite the lower resolution when compared to thin-section analysis, the accuracy of the dual-energy technique is in the range of the standard point counting technique and estimations can be made concerning the microporosity of the samples. Since the developed dual-energy methodology provides a fast and objective determination of the percentages of the mineralogical phases, μCT becomes a very powerful tool in the evaluation of the reservoir potential and in the quantification of mineralogical changes in sedimentary systems (e.g. cycles). In addition, images are acquired visualizing and quantifying the spatial distribution of these phases in three dimensions, which is a major advantage compared to classic 2D thin-section petrography.

An approach to defining tortuosity and cementation factor in carbonate reservoir rocks

Tortuosity and cementation factor are two critical parameters that significantly affect estimates of reservoir properties. Tortuosity factor can be used to estimate permeability using the Carman–Kozeny equation and is an important parameter for formation resistivity factor calculation using a modified version of Archie's formula. It is also used to predict water saturation of reservoir rocks. Tortuosity as an input parameter in Biot's equation can be used to estimate velocity dispersion. In this work, based on the Generalized Archie Equation Curve Fitting (GAECF), tortuosity and cementation factor are determined for selected intervals in a carbonate reservoir. Formation resistivity factor (FRF) analysis was carried out on both core samples and on well log data. The analyses were carried out separately on porous and recognized tight intervals. The intervals selected were fracture-free and include both matrix porosity and somewhat vuggy porosity. FRF analysis on well log data indicates that the carbonate intervals examined follow the GAECF well. However, unreasonable values for the tortuosity parameter, ‘ a’, and cementation factor, ‘ m’, were obtained. To overcome this, the average minimum apparent tortuosity value was calculated for these intervals. Approximate values for tortuosity factor from both core samples and well log data lie close to each other (for porous intervals, zones S1, S7 and S11). This indicates that the results obtained from FRF analysis on well log data can be effectively and reliably used as an alternative to FRF studies on core samples.

Distinguishing Carbonate Reservoir Pore Facies with Nuclear Magnetic Resonance Measurements

Characterization of carbonate rocks may involve identifying the important pore types which are present. In the past, this task has required detailed petrographic analysis of many core samples. Here, we describe a method which uses nuclear magnetic resonance (NMR) measurements to reduce the amount of petrographic analysis needed for porosity typing of carbonate reservoir rocks. For a rock sample which has been measured with NMR, our method decomposes the log(T2) spectrum into at most three Gaussian-shaped components and gives a set of nine parameters. Two characteristic quantities having geological significance are extracted from the nine parameters. Values of the two quantities are compared with a reference set, established from samples having both NMR and petrographic evaluations of porosity types. We use a Bayesian approach to the classification of the dominant porosity type. Tests of our method on 103 samples show a correct prediction in 60 to 90 percent of the samples. The lower success rate was obtained for samples with five porosity types from three fields; the higher success rate obtained with samples with three porosity types from one well. The use of geologically significant quantities extracted from the decomposition gives comparable success rate to those obtained using a standard, non-geological approach such as canonical variates.

General characterization of the seismoelectric effects of the first and second kinds in the Saratov Zavolzh’e region, the Dnieper-Donets basin, and Western Siberia

The seismoelectric effects of the first and second kinds of oil and gas reservoir rocks are studied in three geological regions. Rock samples were taken from deep borehole cores of terrigenous and carbonate composition. Measurements were made in the ultrasound range (100–200 kHz) and at a frequency of 300 Hz. It is shown that the relationship between the porosity coefficient and the intensity of the second-kind seismoelectric effect is the same for terrigenous reservoir rocks in the Saratov Zavolzh’e region, an area of Western Siberia, and the Dnieper-Donets basin. An anomalously strong seismoelectric effect of the first kind (a vibration-induced change in the electrical resistance) is discovered for carbonate reservoir rocks of the Zavolzh’e region.

Use of X-ray powder diffraction for quantitative analysis of carbonate rock reservoir samples

Relative intensity ratio (RIR) method was used to determine the quantitative mineralogy of rock samples that were analyzed by X-ray powder diffraction (XRD). A total of more than 700 samples were tested from wells as deep as 7600 ft located at various carbonate reservoir locations in Arabian Peninsula. Pure mineral samples obtained from the same reservoir were employed as standards to determine relative intensity factors used in the calculations. The rock mineral was mainly composed of calcite, dolomite and anhydrite along with smaller quantities of quartz.

Anomalous Acid Reaction Rates in Carbonate Reservoir Rocks

Summary It is generally assumed that the reaction of acid with limestone reservoir rock is much more rapid than acid reaction with dolomite reservoir rock. This work is the first to show this assumption to be false in some cases, because of mineral impurities commonly found in these rocks. Trace amounts of clay impurities in limestone reservoir rocks were found to reduce the acid dissolution rate by up to a factor of 25, to make the acid reactivity of these rocks similar to that of fully dolomitized rock. A rotating disk instrument was used to measure dissolution rates of reservoir rock from a deep, dolomitic gas reservoir in Saudi Arabia (275°F, 7,500 psi). More than 60 experiments were made at temperatures of 23 and 85°C and HCl concentration of 1.0 M (3.6 wt%). Eight distinctly different rock types that varied in composition from 0 to 100% dolomite were used in this study. In addition, the mineralogy of each rock disk was examined before and after each rotating disk experiment with an environmental scanning electron microscope (ESEM) using secondary and backscattered electron imaging and energy dispersive X-ray (EDS) spectroscopy. Acid reactivity was correlated with the detailed mineralogy of the reservoir rock. It was also shown that bulk anhydrite in the rock samples was converted to anhydrite fines by the acid at 85°C, a potential source of formation damage. Introduction A study of acid reaction rates and reaction coefficients of a dolomitic reservoir rock was recently reported by Taylor et al. (2004a). In that work, it was found that reaction rates depended on mineralogy and the presence of trace components such as clays. This paper examines in detail the relationship between acid reactivity and mineralogy of a deep, dolomitic gas reservoir rock. An accurate knowledge of acid reaction rates of deep gas reservoirs can contribute to the success of matrix and acid fracture treatments. Many studies of acid stimulation treatments of Formation K, a deep, dolomitic gas reservoir in Saudi Arabia, have been published (Nasr-El-Din et al. 2001, 2002a, 2002b; Bartko et al. 2003). It is generally assumed that the reaction of acid with limestone reservoir rock is much more rapid than acid reaction with dolomite reservoir rock during acidizing treatments. However, much of the reported data were obtained with pure limestones, dolomites, and marbles. These include calcite marble (CaCO3) (Lund et al. 1975; de Rozieres 1994; Frenier and Hill 2002), dolomite marble [CaMg(CO3)2] (Lund et al. 1973; Herman and White 1985), Indiana limestone (Mumallah 1991), St. Maximin and Lavoux limestones (Alkattan et al. 1998), Haute Vallée de l'Aude dolomite (Gautelier et al. 1999), Bellefonte dolomite (Herman and White 1985), San Andres dolomite (Anderson 1991), Kasota dolomite (Anderson 1991), and Khuff dolomite reservoir cores (Nasr-El-Din et al. 2002b). The effects of common acid additives on calcite and dolomite dissolution rates were reported in detail (Frenier and Hill 2002; Taylor et al. (2004b; Al-Mohammed et al. 2006). The effects of impurities such as clays on rock dissolution have not been reported.

Origins of CO 2 in permian carbonate reservoir rocks (Zechstein, Ca2) of the NW-German Basin (Lower Saxony)

Permian carbonate reservoir rocks (Stassfurt-Carbonate) of the CO 2-province (Lower Saxony Basin, NW Germany) are locally characterised by high amounts of CO 2 leading to serious problems on exploration. In order to receive information on the major CO 2 sources and CO 2 migration and accumulation processes mineralogical, geochemical and stable isotope analyses ( 13C, 18O) were carried out on authigenic precipitations within the Stassfurt carbonate rocks (Ca2). These rocks contain early diagenetic (e.g., formed in soft sediment) carbonate minerals (calcite, dolomite) and anhydrite in concretions and small cracks. In addition, large (up to 2 cm wide) carbonate-cemented fractures formed in solid Ca2 rocks. Semi-quantitative estimates of the diagenetic mineral content showed variations between the investigated rock cores. Nine out of 12 Ca2 rock cores are derived from wells situated in the area of modern CH 4-rich reservoirs and have distinct fracture systems developed. In contrast, the other three rock cores are from wells characterised by CO 2-rich reservoirs and lack fractures of similar thickness. The assumed relationship between tectonically induced fractures and the gas content of the Ca2 reservoir rocks implies CO 2 degassing of the Ca2 rocks at approximately 102 °C to ∼ 150 °C (assumed δ 18O pore water variation from 0‰ to + 4‰ SMOW). REE distribution indicates at least three types of fracture- and crack-filling carbonates. Two carbonate generations formed from evolving diagenetic pore waters whereas one type reflects carbonate formation under hydrothermal influence. The ages of these cementations derived from Rb/Sr and U/Pb isotope analyses indicate their formation during late stage of/or after the inversion of the Lower Saxony Basin in Late Cretaceous times. The stable carbon isotope composition of the authigenic carbonate minerals reflects at least two carbon source endmembers available during diagenesis. Whereas many early-formed carbonates are related to the Permian 13C-rich carbon source, those carbonates which precipitated or recrystallised during early to late stage diagenesis and/or were induced by local tectonic events incorporated 12C-enriched CO 2 from organic degradation processes. The stable oxygen isotope values of authigenic carbonates probably still reflect low temperatures of mineral formation from Permian sea water (as it is assumed for “non” recrystallised carbonates) or late-stage high-temperature (up to ∼ 150 °C) precipitation from sea water-derived pore waters which may have been locally influenced by 18O-enriched fluids. However, most of the carbonate samples investigated are recrystallised (crystal enlargement of concretionary and fracture carbonate is observed) and hence, these carbonates are at least partly re-equilibrated (original 18O-content reduced) with surrounding pore waters at elevated temperature. Similar to the authigenic carbonate at least two sources may explain the concentration/carbon isotope relationship of modern CO 2 present in the Ca2 reservoir rocks. An organic-derived CO 2 endmember source ( δ 13C near − 20‰) is present in relatively low concentrations whereas large CO 2 concentrations derived from an endmember source with an isotope value near 0‰. Although the latter source is unknown such “heavy” CO 2 sources are most likely attributed to carbonate decomposition processes.

Influences of Droplet Volume on Contact Angle of Reservoir Rocks

Much attention has been devoted to the study of the improved oil recovery (IOR) method(s). However it still remains a challenge to evaluate the reservoir wettability quantitatively using actual core samples. Contact angle is considered as one of the most common methods to measure the preferential affinity of reservoir rocks. The main objectives of this study are to investigate the influences of droplet volume, brine salinity, liquid saturating rocks, oil acid number, and temperature on rock wettability of carbonate reservoir rock using sessile droplet method. Sixteen runs are undertaken using oil droplet volumes of 10, 15, 20, and 25 milliliters with different brine salinities of zero, 50,000, 100,000, and 150,000 ppm of NaCl, respectively, to study the effects of droplet volume and salinity on contact angle. Three runs using three different crude oils having acid numbers of 0.374, 0.561, and 0.986 mg KOH/gm samples are performed to investigate the influence of acid number on contact angle. Three runs are carried out using brine, crude oil and polymer solutions to study the effect of type of liquid saturating rock on contact angle. Finally two runs are used to study the effect of temperature on contact angle. In all experiments, actual rock and crude oil samples are used. The results indicated that there is a specific droplet volume attained at critical water salinity. This critical water salinity is defined to be the salinity at which the oil droplet volume has no effect on contact angle. The rock wettability increases (contact angle decreases) before the critical salinity and increases after it, depending upon the droplet volume. The attained results indicated that the liquid saturating rock has an important role on measured values of contact angle. The results showed that the increase of acid number of the crude oil decreases the contact angle. Therefore, carbonate oil reservoirs containing oils of low acid number are expected to be more oil-wet than ones containing oils of higher acid number. The increase of temperature and bath liquid viscosity reduced the measured contact angle. The results of this study developed a new concept of critical salinity and provided a better understanding of some factors affecting wettability measurements using contact angle technique.

Hydromechanical interactions in a fractured carbonate reservoir inferred from hydraulic and mechanical measurements

Hydromechanical coupled processes in a shallow fractured carbonate reservoir rock were investigated through field experiments coupled with analytical and numerical analyses. The experiments consist of hydraulic loading/unloading of a water reservoir in which fluid flow occurs mainly inside a heterogeneous fracture network made up of vertical faults and bedding planes. Hydromechanical response of the reservoir was measured using six pressure–normal displacement sensors located on discontinuities and two surface tiltmeters. A dual hydraulic behavior was characterized for low-permeability bedding planes well connected to high-permeability faults. Displacement responses show high-variability, nonlinear changes, sometimes with high-frequency oscillations, and a large scattering of magnitudes. Initial normal stiffnesses and effective normal stresses along fault planes were estimated in the field by interpreting pressure–normal displacement relations with a nonlinear function between effective normal stress and normal displacement. Two-dimensional discontinuum modeling with transient fluid flow was performed to fit measurements during hydraulic loading tests. Results show that the hydromechanical behavior of the reservoir is restored if a high stiffness contrast is allocated between low- and high-permeability discontinuities. Thus, a dual-permeability network of discontinuities will likely also be a contrasting stiffness network, in which the deformation of major flow-conducting discontinuities is significantly influenced by the stiffness of the surrounding less-permeable discontinuities.

Prediction of permeability for porous media reconstructed using multiple-point statistics

To predict multiphase flow through geologically realistic porous media, it is necessary to have a three-dimensional (3D) representation of the pore space. We use multiple-point statistics based on two-dimensional (2D) thin sections as training images to generate geologically realistic 3D pore-space representations. Thin-section images can provide multiple-point statistics, which describe the statistical relation between multiple spatial locations and use the probability of occurrence of particular patterns. Assuming that the medium is isotropic, a 3D image can be generated that preserves typical patterns of the void space seen in the thin sections. The method is tested on Berea sandstone for which a 3D image from micro-CT (Computerized Tomography) scanning is available and shows that the use of multiple-point statistics allows the long-range connectivity of the structure to be preserved, in contrast to two-point statistics methods that tend to underestimate the connectivity. Furthermore, a high-resolution 2D thin-section image of a carbonate reservoir rock is used to reconstruct 3D structures by the proposed method. The permeabilities of the statistical images are computed using the lattice-Boltzmann method (LBM). The results are similar to the measured values, to the permeability directly computed on the micro-CT image for Berea and to predictions using analysis of the 2D images and the effective medium approximation.