Showing papers on "Petroleum reservoir published in 2018"

Petroleum reservoir quality prediction: overview and contrasting approaches from sandstone and carbonate communities

Abstract: Abstract The porosity and permeability of sandstone and carbonate reservoirs (known as reservoir quality) are essential inputs for successful oil and gas resource exploration and exploitation. This chapter introduces basic concepts, analytical and modelling techniques and some of the key controversies to be discussed in 20 research papers that were initially presented at a Geological Society conference in 2014 titled ‘Reservoir Quality of Clastic and Carbonate Rocks: Analysis, Modelling and Prediction’. Reservoir quality in both sandstones and carbonates is studied using a wide range of techniques: log analysis and petrophysical core analysis, core description, routine petrographic tools and, ideally, less routine techniques such as stable isotope analysis, fluid inclusion analysis and other geochemical approaches. Sandstone and carbonate reservoirs both benefit from the study of modern analogues to constrain the primary character of sediment before they become a hydrocarbon reservoir. Prediction of sandstone and carbonate reservoir properties also benefits from running constrained experiments to simulate diagenetic processes during burial, compaction and heating. There are many common controls on sandstone and carbonate reservoir quality, including environment of deposition, rate of deposition and rate and magnitude of sea-level change, and many eogenetic processes. Compactional and mesogenetic processes tend to affect sandstone and carbonate somewhat differently but are both influenced by rate of burial, and the thermal and pressure history of a basin. Key differences in sandstone and carbonate reservoir quality include the specific influence of stratigraphic age on seawater composition (calcite v. aragonite oceans), the greater role of compaction in sandstones and the greater reactivity and geochemical openness of carbonate systems. Some of the key controversies in sandstone and carbonate reservoir quality focus on the role of petroleum emplacement on diagenesis and porosity loss, the role of effective stress in chemical compaction (pressure solution) and the degree of geochemical openness of reservoirs during diagenesis and cementation. This collection of papers contains case study-based examples of sandstone and carbonate reservoir quality prediction as well as modern analogue, outcrop analogue, modelling and advanced analytical approaches.

Estimating in situ rock mass strength and elastic modulus of granite from the Soultz-sous-Forêts geothermal reservoir (France)

Abstract: Knowledge of the strength and elastic modulus of a reservoir rock is important for the optimisation of a particular geothermal resource. The reservoir rock for many geothermal projects in the Upper Rhine Graben, such as those at Soultz-sous-Forets and Rittershoffen (both France), is porphyritic granite. High fracture densities (up to ~ 30 fractures/m) in this reservoir rock require that we consider the strength and elastic modulus of the rock mass, rather than the intact rock. Here we use uniaxial and triaxial deformation experiments performed on intact rock coupled with Geological Strength Index assessments—using the wealth of information from core and borehole analyses—to provide rock mass strength and elastic modulus estimates for the granite reservoir at Soultz-sous-Forets (from a depth of 1400 to 2200 m) using the generalised Hoek–Brown failure criterion. The average uniaxial compressive strength and elastic modulus of the intact granite are 140 MPa (this study) and 40 GPa (data from this study and the literature), respectively. The modelled strength of the intact granite is 360 MPa at a depth of 1400 m and increases to 455 MPa at 2200 m (using our estimate for the empirical m i term of 30, determined using triaxial and tensile strength measurements on the intact granite). Strength of the rock mass varies in accordance with the fracture density and the extent and nature of the fracture infill, reaching lows of ~ 40–50 MPa (in, for example, the densely fractured zones in EPS-1 at depths of ~ 1650 and ~ 2160 m, respectively) and highs of above 400 MPa (in, for example, the largely unfractured zone at a depth of ~ 1940–2040 m). Variations in rock mass elastic modulus are qualitatively similar (values vary from 1 to 2 GPa up to the elastic modulus of the intact rock, 40 GPa). Our study highlights that macrofractures and joints reduce rock mass strength and should be considered when assessing the rock mass for well stability and rock mass deformation due to stress redistribution in the reservoir. We present a case study to demonstrate how a simple and cost-effective engineering method can be used to provide an indication of the in situ strength and elastic modulus of reservoir rock masses, important for a wide range of modelling and stimulation strategies. We recommend that the effect of macrofractures on rock mass strength and stiffness be validated for incorporation into geomechanical characterisation for geothermal reservoirs worldwide.

Thermophilic endospores associated with migrated thermogenic hydrocarbons in deep Gulf of Mexico marine sediments.

Abstract: Dormant endospores of thermophilic bacteria (thermospores) can be detected in cold marine sediments following high-temperature incubation. Thermospores in the cold seabed may be explained by a dispersal history originating in deep biosphere oil reservoir habitats where upward migration of petroleum fluids at hydrocarbon seeps transports viable cells into the overlying ocean. We assessed this deep-to-shallow dispersal hypothesis through geochemical and microbiological analyses of 111 marine sediments from the deep water Eastern Gulf of Mexico. GC-MS and fluorescence confirmed the unambiguous presence of thermogenic hydrocarbons in 71 of these locations, indicating seepage from deeply sourced petroleum in the subsurface. Heating each sediment to 50 °C followed by 16S rRNA gene sequencing revealed several thermospores with a cosmopolitan distribution throughout the study area, as well as thermospores that were more geographically restricted. Among the thermospores having a more limited distribution, 12 OTUs from eight different lineages were repeatedly detected in sediments containing thermogenic hydrocarbons. A subset of these were significantly correlated with hydrocarbons (p < 0.05) and most closely related to Clostridiales previously detected in oil reservoirs from around the world. This provides evidence of bacteria in the ocean being dispersed out of oil reservoirs, and suggests that specific thermospores may be used as model organisms for studying warm-to-cold transmigration in the deep sea.

CO2 Injection Effect on Geomechanical and Flow Properties of Calcite-Rich Reservoirs

Abstract: Geologic carbon storage is considered as a requisite to effectively mitigate climate change, so large amounts of carbon dioxide (CO2) are expected to be injected in sedimentary saline formations CO2 injection leads to the creation of acidic solution when it dissolves into the resident brine, which can react with reservoir rock, especially carbonates We numerically investigated the behavior of reservoir-caprock system where CO2 injection-induced changes in the hydraulic and geomechanical properties of Apulian limestone were measured in the laboratory We found that porosity of the limestone slightly decreases after CO2 treatment, which lead to a permeability reduction by a factor of two In the treated specimens, calcite dissolution was observed at the inlet, but carbonate precipitation occurred at the outlet, which was closed during the reaction time of three days Additionally, the relative permeability curves were modified after CO2–rock interaction, especially the one for water, which evolved from a quadratic to a quasi-linear function of the water saturation degree Geomechanically, the limestone became softer and it was weakened after being altered by CO2 Simulation results showed that the property changes occurring within the CO2 plume caused a stress redistribution because CO2 treated limestone became softer and tended to deform more in response to pressure buildup than the pristine rock The reduction in strength induced by geochemical reactions may eventually cause shear failure within the CO2 plume affected rock This combination of laboratory experiments with numerical simulations leads to a better understanding of the implications of coupled chemo-mechanical interactions in geologic carbon storage

Application of instantaneous spectral analysis and acoustic impedance wedge modeling for imaging the thin beds and fluids of fluvial sand systems of Indus Basin, Pakistan

Abstract: Fluvial sand frameworks have magnificent oil and gas reservoirs far and wide. The reservoir sands are exceedingly compartmentalized by the broadened fault framework. So, to distinguish the thin beds of gas-bearing facies is an assessment for band-limited stratigraphic investigation. To conquest this issue, we execute the progressed seismic ascribe methods to the 3D seismic information of the Miano area of the Indus Basin, SW Pakistan. Apparatuses, for example, the seismic amplitude and coherence are discovered less exact for reservoir description. Sweetness analysis indicates the gas-bearing reservoir facies, which are compartmentalized by the NNW–SSE oriented normal fault system. Yet, the continuous wavelet transforms (CWT) of spectral decomposition (SD) separates the thick and thin sand beds of channel sand and point bars, which were not unsurprising utilizing the band-limited seismic properties. 22 Hz demonstrates the best amplitude tuning cube, which recognizes the profitable clastic (sand-filled barrier bars) sequences. The net-to-gross (N/G) examination uncovers the barrier bars as the chief hydrocarbon-bearing facies. 22 to 37 Hz frequencies confirm the occurrence of hydrocarbon sands. The acoustic impedance (AI) wedge model settles the thin beds of barrier bars sands, which are encased inside the shales, and affirm the suggestions for gas-bearing stratigraphic traps.

CO2 Miscible Flooding for Enhanced Oil Recovery

Abstract: Carbon capture aims to mitigate the emission of CO2 by capturing it at the point of combustion then storing it in geological reservoirs or applied through enhanced oil recovery (EOR) in a technology known as miscible flooding, so reduce CO2 atmospheric emissions Miscible CO2-EOR employs supercritical CO2 to displace oil from a depleted oil reservoir CO2 improve oil recovery by dissolving in, swelling, and reducing the oil viscosity Hydrocarbon gases (natural gas and flue gas) used for miscible oil displacement in some large reservoirs These displacements may simply amount to "pressure maintenance" in the reservoir In such flooding techniques, the minimum miscibility pressure determined through multiple contact experiments and swelling test to determine the optimum injection conditions

A Review of Reservoir Rock Typing Methods in Carbonate Reservoirs: Relation between Geological, Seismic, and Reservoir Rock Types

Abstract: Carbonate reservoirs rock typing plays a pivotal role in the construction of reservoir static models and volumetric calculations. The procedure for rock type determination starts with the determination of depositional and diagenetic rock types through petrographic studies of the thin sections prepared from core plugs and cuttings. In the second step of rock typing study, electrofacies are determined based on the classification of well log responses using an appropriate clustering algorithm. The well logs used for electrofacies determination include porosity logs (NPHI, DT, and RHOB), lithodensity log (PEF), and gamma ray log. The third step deals with flow unit determination and pore size distribution analysis. To this end, flow zone indicator (FZI) is calculated from available core analysis data. Through the application of appropriate cutoffs to FZI values, reservoir rock types are classified for the studying interval. In the last step, representative capillary pressure and relative permeability curves are assigned to the reservoir rock types (RRT) based upon a detailed analysis of available laboratory data. Through the analysis of drill stem test (DST) and GDT (gas down to) and ODT (oil down to) data, necessary adjustments are made on the generated PC curves so that they are representative of reservoir conditions. Via the estimation of permeability by using a suitable method, RRT log is generated throughout the logged interval. Finally, by making a link between RRT’s and an appropriate set of seismic attributes, a cube of reservoir rock types is generated in time or depth domain. The current paper reviews different reservoir rock typing approaches from geology to seismic and dynamic and proposes an integrated rock typing workflow for worldwide carbonate reservoirs.

Capillary pressure and relative permeability correlations for transition zones of carbonate reservoirs

Abstract: A sizable oil reserves are held in a thick oil/water capillary transition zones in the carbonate reservoirs, but it is an ongoing challenge to accurately describe the relationship between capillary pressure, relative permeability and oil/water saturation due to the complex wettability variation, pore geometry and heterogeneity throughout the reservoir column. It has been shown that a proper interpretation of relative permeability and capillary pressure including hysteresis has a substantial influence on the prediction and optimization of field production, especially for a heterogeneous carbonate reservoir with a thick transition zone. The conventional models, such as Corey method and Leverett J-function, cannot precisely present the behaviors of capillary pressure and relative permeability of transition zones in carbonate reservoirs. In the present work, a study has been conducted to provide an improved understanding of capillary pressure and relative permeability of the transition zones in carbonate reservoirs by implementing and optimizing recently developed models considering mixed-wet property and geological heterogeneity. For single core plug and each reservoir rock typing classified on the basis of petrophysical properties, the applicability to generate bounding drainage and imbibition curves of the models was tested with fitting parameters by comparing with experimental data. Also, a comprehensive assessment was provided about the feasibility and efficiency of the models along with an evaluation of the hysteresis between bounding drainage and imbibition curves. The results showed excellent matches in the case of Masalmeh model (SPE Reserv Eval Eng 10(02):191–204, 2007) with a correlation coefficient value of 0.95, in which mixed-wet and pore size distribution are taken into account. Therefore, it can be stated that the work conducted in this study could be used as a guide for further investigation and understanding of transition zones in carbonate reservoirs.

Outcrop analogue study to determine reservoir properties of the Los Humeros and Acoculco geothermal fields, Mexico

Abstract: . The Los Humeros geothermal system is steam dominated and currently under exploration with 65 wells (23 producing). Having temperatures above 380 ∘ C, the system is characterized as a super hot geothermal system (SHGS). The development of such systems is still challenging due to the high temperatures and aggressive reservoir fluids which lead to corrosion and scaling problems. The geothermal system in Acoculco (Puebla, Mexico; so far only explored via two exploration wells) is characterized by temperatures of approximately 300 ∘ C at a depth of about 2 km. In both wells no geothermal fluids were found, even though a well-developed fracture network exists. Therefore, it is planned to develop an enhanced geothermal system (EGS). For better reservoir understanding and prospective modeling, extensive geological, geochemical, geophysical and technical investigations are performed within the scope of the GEMex project. Outcrop analogue studies have been carried out in order to identify the main fracture pattern, geometry and distribution of geological units in the area and to characterize all key units from the basement to the cap rock regarding petro- and thermo-physical rock properties and mineralogy. Ongoing investigations aim to identify geological and structural heterogeneities on different scales to enable a more reliable prediction of reservoir properties. Beside geological investigations, physical properties of the reservoir fluids are determined to improve the understanding of the hydrochemical processes in the reservoir and the fluid-rock interactions, which affect the reservoir rock properties.

Integrated Reservoir Characterization Study of the McKee Formation, Onshore Taranaki Basin, New Zealand

Abstract: The Late Eocene onshore McKee Formation is a producing reservoir rock in Taranaki Basin, New Zealand. An integrated petrophysical, sedimentological, and petrographical study was conducted to evaluate the reservoir characteristics of the McKee sandstone. A petrographic study of the McKee Formation classified the sandstone as arkose based on the Pettijohn classification. Porosity analysis showed predominantly intergranular porosity, as elucidated by the thin section photomicrographs. The good reservoir quality of McKee sandstone was suggested to be the result of the presence of secondary dissolution pores interconnected with the primary intergranular network. Mineral dissolution was found to be the main process that enhanced porosity in all the studied wells. On the other hand, the presence of clay minerals, cementation, and compaction were identified as the main porosity-reducing agents. These features, however, were observed to occur only locally, thus having no major impact on the overall reservoir quality of the McKee Formation. For a more detailed reservoir characterization, well log analysis was also applied in the evaluation of the McKee Formation. The result of the well log analysis showed that the average porosity ranged from 11.8% to 15.9%, with high hydrocarbon saturation ranging from 61.8% to 89.9% and clay volume content ranging from 14.9 to its highest value of 34.5%. Based on the well log analysis, the derived petrophysical and reservoir parameters exhibited good porosity, low clay content, and high hydrocarbon saturation, which indicates that the McKee Formation is a promising reservoir.

Linking Natural Oil Seeps from the Gulf of Mexico to Their Origin by Use of Fourier Transform Ion Cyclotron Resonance Mass Spectrometry

Abstract: We report chemical characterization of natural oil seeps from the Gulf of Mexico by Fourier transform ion cyclotron resonance mass spectrometry (FT-ICR MS) and Gas Chromatography/Atmospheric Pressure Chemical Ionization Mass Spectrometry (GC/APCI-MS), to highlight how FT-ICR MS can also be employed as a means to determine petroleum connectivity, in addition to traditional GC/MS techniques. The source of petroleum is the Green Canyon (GC) 600 lease block in the Gulf of Mexico. Within GC600, two natural oil seepage zones, Mega Plume and Birthday Candles, continuously release hydrocarbons and develop persistent oil slicks at the sea surface above them. We chemically trace the petroleum from the surface oil slicks to the Mega Plume seep itself, and further to a petroleum reservoir 5 km away in lease block GC645 (Holstein Reservoir). We establish the connectivity between oil samples and confirm a common geological origin for the oil slicks, oil seep, and reservoir oil. The ratios of seven common petroleum biom...

Width Evolution of the Hydraulic Fractures in Different Reservoir Rocks

Abstract: Hydraulic fracturing has become an important technology in the development and exploitation of unconventional gas (including tight sand gas and shale gas) and geothermal resources. The fracture networks constitute of hydraulic fractures, and natural fractures provide the pathways for fracturing fluid and gas molecular. In recent decades, many researches of numerical simulation and experiments into this issue had been performed. To reveal the fracture patterns, Pradhan et al. (2015) investigated stress-induced fracturing in sandstone and limestone cores by acoustic monitoring and microcomputed tomography image analysis. Renard et al. (2009) studied the 3D imaging of hydraulic fracture propagation in limestone cores using synchrotron X-ray microtomography. The results showed that hydraulic fractures propagated by the linkage of the pores. Lin et al. (2017) investigated the anisotropic characteristics of Longmaxi Shale in hydraulic fracturing experiments. The research by He et al. (2016) demonstrated the effects of anisotropy and heterogeneity on the pathways of hydraulic fractures in reservoir rocks. It is recognized that the width of hydraulic fractures is an important parameter in the stimulation of hydraulic fracturing operation (Neto and Kotousov 2012; Mcclure 2012; Zhang et al. 2016). In addition, in the operation of hydraulic fracturing, the proppant is usually pumped into the fracture networks with the fracturing fluid to support the induced fractures. To ensure the effectiveness of proppant, the size of proppant is important in the design of field hydraulic fracturing operation. So the width of hydraulic fractures is an important parameter for the selection of proppant size. Abousleiman et al. (2014) studied the effects of the temperature difference between hydraulic fracturing fluid and rock formation on the time-dependent evolution of fracture width using a newly derived one-dimensional anisotropic porothermoelastic analytical solution. By combining the information of both compressional and shear wave measurements, Groenenboom et al. (2001) measured the shape and geometry during the growth of hydraulic fractures. Based on the continuum thermoporoelastic theory, Tran et al. (2012) developed a new analytical formula of fracture width to quickly predict its transient growth or decay. Mohammadnejad and Andrade (2016) developed a fully coupled model for numerical modeling of hydraulic fracture propagation, closure and reopening in partially saturated weak porous formations using the extended finite element method. According to the experiment and simulation results by Kang et al. (2015) for northwestern Sichuan tight gas reservoir, the in situ fracture width is 3.28–18.59 μm and the dynamic fracture width is 17.89–763 μm. In this article, hydraulic fracturing experiments were conducted under the same conditions (including injection rate, axial stress and confining pressure) to investigate the width evolution behavior of hydraulic fractures during the hydraulic fracturing process. X-ray CT scanning technology was employed to obtain the hydraulic fracture morphology of fractured rock specimens. In addition, the fracture widths were firstly calculated based on the data of CT scanning results and monitoring of circumference during the fracturing process. * Jianming He hjm@mail.iggcas.ac.cn

Characterization of a fractured basement reservoir using high-resolution 3D seismic and logging datasets: A case study of the Sab'atayn Basin, Yemen.

Abstract: The Sab’atayn Basin is one of the most prolific Mesozoic hydrocarbon basins located in central Yemen. It has many oil producing fields including the Habban Field with oil occurrences in fractured basement rocks. A comprehensive seismic analysis of fractured basement reservoirs was performed to identify the structural pattern and mechanism of hydrocarbon entrapment and reservoir characteristics. A 3D post-stack time migration seismic cube and logging data of 20 wells were used and several 2D seismic sections were constructed and interpreted. Depth structure maps were generated for the basement reservoir and overlying formations. The top of the basement reservoir is dissected by a set of NW-SE step-like normal faults (Najd Fault System) and to a lesser extent, by secondary NNE-SSW oriented faults (Hadramauwt System). The Najd Fault System is dominant and dissects the reservoir in the middle of the field into two prospective uplifts. The northern and northeastern areas constitute the deep-seated downthrown side of the reservoir. Hydrocarbon emplacement is through the fault juxtaposition of the fractured basement against the organic shale source rock of the overlying Madbi Formation. Hydrocarbons are hosted in basement horsts formed by fault-controlled blocks and overlain by the regional seal of the Sab’atayn Formation. The basement reservoir rock is mainly composed of granite, quartz-feldspar, weathered silica, and mica minerals. Fractures were identified from the outcrops, cores, image logs, and the petrophysical analysis. Hydrocarbon saturation was observed in the upper and middle parts of the reservoir, more specifically in front of the highly fractured sections. The fracture porosity was less than 5% and the dead oil had an API gravity of 40° with no H2S or CO2. In conclusion, the structural highs of the Habban Field are of interest because most oil producing wells are drilled into them. We recommend extending the drilling and development activities in these uplifts.