Properties Of Carbonate Reservoirs Research Articles

Investigation of factors influencing geological heterogeneity in tight gas carbonates, Permian reservoir of the Persian Gulf

Understanding the spatial distribution of petrophysical properties in carbonate reservoirs is complicated due to their heterogeneity and sensitivity to diagenesis along with important facies variations. The reservoir evaluation in tight carbonates is even more complicated. The Permian Dalan Formation in the central part of Persian Gulf is generally considered as conventional carbonate reservoir. However, in this study, a part of K3 unit of this formation is introduced as a tight carbonate reservoir. To identify the factors influencing the quality of this unit, the sedimentary facies, depositional environments, diagenetic processes, and pore-type distribution were studied in details on 402 thin sections. Porosity and permeability of K3 are mainly controlled by dolomitization, dissolution, compaction, and cementation. MICP-based (mercury injection capillary pressure) methods, FZI*(FZI-star), and rock fabric numbers were considered to recognize the factors controlling heterogeneity of this unit. The MICP-based methods of Winland, Pittman, and Rezaee were combined with 3 porosity cutoffs to detect the heterogeneities of tight carbonates. None of these methods provided a high degree of correlation between porosity and permeability of the samples. The results of rock fabric number showed that samples with similar reservoir quality are the product of different diagenetic processes. Results obtained in this study demonstrate that the FZI*(FZI-star) and rock fabric number classifications are the most suitable methods for differentiating the tight zone and non-reservoir/reservoir parts in carbonates of K3 unit.

Grid density overlapping hierarchical algorithm for clustering of carbonate reservoir rock types: A case from Mishrif Formation of West Qurna-1 oilfield, Iraq

The primary goal of this study is to solve a major challenge of reservoir rock typing in quantitatively understanding the relationship between geological and petrophysical properties of carbonate reservoir. This paper first presents an improved overlapping index based on the grid density to define the overlapping relationship between different clusters and a grid density overlapping hierarchical algorithm (GDOH) for clustering of carbonate reservoir rock types. GDOH clustering algorithm is a hybrid type which integrates the gird, density, overlapping index and the hierarchical clustering method using the number of grid divisions and the threshold value of the overlapping index as the key parameters. Taking the Mishrif Formation of West Qurna Oilfield-1 as a case, the GDOH clustering algorithm is employed for clustering of carbonate reservoir rock types. As a result, ten geological rock types are identified according to the lithological type and diagenetic type using the thin section data. We finally got four reservoir rock types using the GDOH clustering algorithm with the overlapping index of core porosity and the permeability data as the metric. These reservoir rock types are different in reservoir qualities and porosity-permeability relationships. Each reservoir rock type also shows a similar set of capillary pressure curves and a typical and unique set of pore throat size distribution. The clustering result gives us some clues to understand the control of depositional and diagenesis features on the variation of reservoir rock types in reservoir quality and porosity-permeability relationship. Compared with the model-based petrophysical rock-typing techniques such as Winland r35, FZI and FZI-Star (FZI*), GDOH algorithm shows some apparent advantages in the evaluation of reservoir quality and prediction of permeability in three dimensions based on geologic principles in addition to understanding the relationship between reservoir rock type and petrophysical static and dynamic rock type.

Permeability upscaling in complex carbonate samples using textures of micro-computed tomography images

ABSTRACT Developing a better characterization of fluid flow properties in carbonate reservoirs is a critical step for enhanced oil recovery applications in the oil industry. Indeed, carbonate reservoirs rocks are in general highly heterogeneous with variability revealed from submicron to centimeters. In several studies, Digital Rock Physics (DRP) was implemented as a technique which aims to help characterizing rock properties behavior at pore scale. This approach uses 3D X-ray micro tomography images to characterize pore network and also simulate rock properties from these images. Even though DRP is able to predict realistic rock properties in sandstone reservoirs it is still suffering from a lack of clear workflow in carbonate rocks. The main challenge is the upscaling of simulated properties from fine to coarse. In this paper, we propose a new upscaling method to characterize absolute permeability in carbonate core plugs samples using textures of Micro-Computed Tomography images. We propose to classify 3D micro-CT images of rock samples in terms of textures and predict the overall rock permeability. Finally, we discuss the advantages and limitations of this new approach. Overall the present work proposes an efficient and faster alternative DRP workflow for upscaling from pore-scale to core-scale.

Effect of hysteresis on petrophysical properties of limestone hydrocarbon reservoir rock

Abstract The petrophysical properties of carbonate reservoirs may change when they are subjected to mechanical loadings due to the softness of the formation. As the reservoir fluid pressure declines due to production, the net load on the rock increases, which leads to compaction of the rock and decrease in its pore volume, causing blocking of pore throats and the permeability reduction. In this study, we experimentally investigated the hysteresis effect of petrophysical properties of two carbonate core samples during the loading using CMS-300 apparatus. The structure of samples was processed by CT scan images and analysis of the pore size distribution was also conducted using mercury injection testing followed by scanning electron microcopy (SEM). Our results indicate that isotropic long-term and short-term loading considerably change the grain structure, while the petrophysical properties do not have a clear effect. The porosity induced by the cyclic loading was affected by intergranular micro-extension fractures. The results also indicate that the greatest reduction of porosity in fractured limestone occurred at the first loading step; however, further reduction was strongly due to the consolidation and adherence of the grain matrix. This fluctuating trend was also observed for the permeability, with a severe reduction in the permeability when crushed grains were placed in the connected pore path. The measured porosity and permeability of carbonated rocks, as stress-sensitive parameters, along analysis of the micro-fracture effects during loading and unloading, can be considered in production and injection management of reservoirs. They are also useful for predicting of any possible risks during different periods of reservoir life and determining the optimum production pressure of the reservoir.

The equivalent pore aspect ratio as a tool for pore type prediction in carbonate reservoirs

The equivalent pore aspect ratio provides a tool to detect pore types by combining compressional and shear wave velocities, porosity, bulk density, and mineralogical composition of carbonate rocks. The integration of laboratory measurements, well logs, and petrographic analysis of carbonate rocks from various depositional and diagenetic settings (Lower Cretaceous presalt nonmarine carbonates from offshore Brazil; Lower Cretaceous shallow-water platform carbonates from southeast France; and Upper Cretaceous deep-water carbonate from the Gargano Peninsula, Italy) allowed the acoustic signature of a wide range of pore types to be quantified. The equivalent pore aspect ratios are shown to be independent of pore volume and mineralogy. They can, therefore, be regarded as relevant parameters for discriminating selected pore network architectures in carbonate reservoirs. Interparticle and intercrystalline microporosity and macroporosity may include a variety of distinct pore network structures and a wide range of acoustic signatures depending on particle shape, nature of contacts, packing, and cementation (intergranular macroporosity in a densely packed granular sediment, secondary pseudofenestral, etc.). The acoustic response of moldic pores appears to be mainly controlled by the shape of the dissolved allochems. The present work reveals also that correct pore type detection from acoustic and porosity measurements is highly dependent on the pore type classification used. A selection of petrographic and diagenetic features to be considered for the construction of a suitable pore type classification is proposed to improve the detection of the pore type effect on the acoustic properties of carbonate reservoirs at plug and well log scale.

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

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.

Toward Reservoir-on-a-Chip: Fabricating Reservoir Micromodels by in Situ Growing Calcium Carbonate Nanocrystals in Microfluidic Channels.

We introduce a novel and simple method to fabricate calcium carbonate (CaCO3) micromodels by in situ growing a thin layer of CaCO3 nanocrystals with a thickness of 1-2 μm in microfluidic channels. This approach enables us to fabricate synthetic CaCO3 reservoir micromodels having surfaces fully covered with calcite, while the dimensions and geometries of the micromodels are controllable on the basis of the original microfluidic channels. We have tuned the wettability of the CaCO3-coated microchannels at simulated oil reservoir conditions without introducing any chemical additives to the system; thus the resulting oil-wet surface makes the micromodel more faithfully resemble a natural carbonate reservoir rock. With the advantage of its excellent optical transparency, the micromodel allows us to directly visualize the complex multiphase flows and geochemical fluid-calcite interactions by spectroscopic and microscopic imaging techniques. The CaCO3-coated microfluidic channels provide new capabilities as a micromodel system to mimic real carbonate reservoir properties, which would allow us to perform a water-oil displacement experiment in small-volume samples for the rapid screening of candidate fluids for enhanced oil recovery (EOR). The immiscible fluid displacement process within carbonate micromodels has been demonstrated showing the water-oil-carbonate interactions at pore-scale in real time by fluorescence microscopic imaging.

Anisotropic rock physics models for interpreting pore structures in carbonate reservoirs

We developed an anisotropic effective theoretical model for modeling the elastic behavior of anisotropic carbonate reservoirs by combining the anisotropic self-consistent approximation and differential effective medium models. By analyzing the measured data from carbonate samples in the TL area, a carbonate pore-structure model for estimating the elastic parameters of carbonate rocks is proposed, which is a prerequisite in the analysis of carbonate reservoirs. A workflow for determining elastic properties of carbonate reservoirs is established in terms of the anisotropic effective theoretical model and the pore-structure model. We performed numerical experiments and compared the theoretical prediction and measured data. The result of the comparison suggests that the proposed anisotropic effective theoretical model can account for the relation between velocity and porosity in carbonate reservoirs. The model forms the basis for developing new tools for predicting and evaluating the properties of carbonate reservoirs.

Effects of structural segmentation and faulting on carbonate reservoir properties: A case study from the Central Uplift of the Tarim Basin, China

The largest condensate field of the Ordovician reef-shoal reservoirs, in China, was discovered along the N°1 fault zone in the Tarim Basin. However, current drilling activities are hindered by the low and unstable production from these carbonate reservoirs. A detailed structural analysis of 3-D seismic data identified three segments along the N°1 fault zone characterized by differences in structural geometry and evolution. Segmentation of the N°1 fault zone has resulted in the variation of characteristics and distribution of the Upper Ordovician carbonate reservoirs. Due to fault induced differential uplift before the Late Ordovician, a narrow and thick-rimmed platform margin rich in reefs has developed in the eastern segment, whereas wider and thinner shoals developed in the central and western segments. We clearly identified a fault block uplift related erosional unconformity, and associated karstification at the top of the Upper Ordovician carbonates in the eastern segment. In this segment, the karst caves resulted in the high and stable hydrocarbon production. In the central segment, good matrix reservoirs exist, but due to the lack of fault-related enhancement of the reservoirs quality, only relatively low production is observed. In the western segment, where fracture-vug reservoirs occurred in relation to later fault damage zones, production is much greater but unstable. Large-scale fracture-caves reservoirs related to fault activity, rather than the good unfaulted matrix reservoirs, lead to the high production of oil and gas. We classify these reef-shoal reservoirs as faulting modified reservoirs. Further exploitation should focus more on the fault damage zone beyond the platform margin rather than the microfacies in the Lower Paleozoic carbonates.

Application of Conventional Well Logs To Characterize Spatial Heterogeneity in Carbonate Formations Required for Prediction of Acid-Fracture Conductivity

SummaryAcid etching, as the consequence of heterogeneous distribution of petrophysical and compositional properties, results in the conductivity of acid fractures in carbonate reservoirs. Reliable characterization of small-scale formation spatial heterogeneity by use of geostatistical analysis (i.e., variogram analysis) can improve prediction of acid-fracture conductivity significantly. Previous publications suggest that permeability correlation length can be used to assimilate spatial heterogeneity in prediction of acid-fracture conductivity. Well logs are good candidates to provide information about petrophysical and compositional properties of the formation with the required resolution for prediction of acid-fracture conductivity. However, the assessment of permeability and mineralogy from conventional well logs is challenging because of high spatial heterogeneity and complex pore structure. Rock typing has been suggested in the literature to improve permeability assessment in carbonates. Most of the previously introduced rock-typing methods are dependent on core measurements. However, core data are generally sparse and not available with the sampling rate required for prediction of acid-fracture conductivity.The main objective of this paper is to quantify formation spatial heterogeneity with variogram analysis of well logs and well-log-based estimates of petrophysical and compositional properties in carbonate reservoirs. We introduce an iterative permeability-assessment technique that is based on well logs, which takes into account characteristics of different rock classes in the reservoir. Furthermore, we propose three rock-classification techniques that are based on conventional well logs and that take into account static and dynamic petrophysical properties of the formation as well as mineral composition.We applied the proposed techniques successfully in two carbonate formations—Happy Spraberry oil field and Hugoton gas field. The petrophysical rock classification is in good agreement with identified core-derived rock classes. The results show approximately 54% improvement in permeability assessment compared with conventional permeability-assessment techniques, which can improve prediction of acid-stimulation jobs significantly. Finally, we investigated the direct application of well logs and well-log-based estimates of petrophysical and compositional properties for variogram analysis required to characterize formation spatial heterogeneity. We conducted variogram analysis in both field examples. The results show that the direct application of well logs and well-log-based estimates of petrophysical/compositional properties is reliable to characterize formation spatial heterogeneity. We also showed that application of well logs can enhance assessment of spatial heterogeneity compared with core measurements.

Alteration of Wettability by Cationic Gemini and Conventional Surfactants for Carbonate Reservoirs

Carbonate reservoir properties are complicated to understand. Out of these properties altering wettability is an important property to be considered for oil recovery. The aim of this research work is to compare the amount of oil recovered by applying cationic gemini and its original form. An investigation was conducted on Cationic gemini form of Cetyl Tri Alkyl Bromide (CTAB) and its conventional form on carbonate cores for wettability alteration. The concentrations for surfactants were selected on the basis of conductivity test. During core flooding oil recovery through these surfactants has been compared. Gemini 16-3-16,2Br has shown 0.35 pore volume additional recovery than CTAB.

An experimental study of solid matrix weakening in water‐saturated Savonnières limestone

ABSTRACTPetrophysical properties of carbonate reservoirs are less predictable than that of siliciclastic reservoirs. One of the main reasons for this is the physical and chemical interactions of carbonate rocks with pore fluids. Such interactions can significantly change the elastic properties of the rock matrix and grains, making the applicability of Gassmann's fluid substitution procedure debatable. This study is an attempt to understand the mechanisms of fluid‐rock interactions and the influence of these interactions on elastic parameters of carbonates. We performed precise indentation tests on Savonnières limestone at a microscale level under dry, distilled water, and n‐Decane saturated conditions. Our experiments display softening of the rock matrix after water saturation. We have found that mainly the ooid cortices, peloid nuclei and prismatic intergranular cement are affected by water flooding. We also observed a shear modulus reduction in Savonnières limestone in an experiment performed at ultrasonic frequencies. One of the most important results obtained in our experimental study is that the Gassmann fluid substitution theory might not always be applicable to predict the elastic moduli of fluid‐saturated limestones.

Estimation of Carbonate Elastic Properties from Nanoindentation Experiments to Reduce Uncertainties in Reservoir Modelling

Petrophysical properties of carbonate reservoirs, which are the majority of all hydrocarbon reservoirs worldwide, are much less predictable than the properties of siliciclastic reservoirs. This is mainly due to chemical interactions of carbonate rocks with percolating fluids that cause dissolution, ion exchange, and recrystallization in geological time. These processes result in dramatic changes in density, porosity, and permeability leading to inhomogeneity of carbonate rocks on micro- and meso- scales. Quantification of the elastic variability of carbonate grains on the microscale is the first step to constrain models and to obtain more realistic predictions of practically important rock properties of carbonate reservoirs. In this study, we present elastic moduli of an oolite sample from the Dampier Formation - Pleistocene of Southern Carnarvon Basin, Western Australia, obtained by nanoindentation. Young?s moduli of this highly heterogeneous sample are measured at 49 points regularly distributed in a 70x70micrometer rectangular grid on the sample?s surface. The frequency diagram shows bimodal distribution of the Young?s moduli oriented around values of 56 GPa and 144 GPa that correspond to low and high density components of the grain respectively. These two solid phases are apparent in the high resolution scanning electron microscope images. We used the obtained moduli of this composite grain for numerical modelling using finite element approach of elastic properties of the carbonate sample from micro-Computed Tomography images. The results compare favourably with the elastic moduli obtained from acoustic velocities measured by ultrasonic technique.

Fifty Years of Wettability Measurements in the Arab-D Carbonate Reservoir

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 105114, "Fifty Years of Wettability Measurements in the Arab-D Carbonate Reservoir," by T.M. Okasha, SPE, J.J. Funk, SPE, and H.N. Al-Rashidi, SPE, Saudi Aramco, prepared for the 2007 SPE Middle East Oil & Gas Show and Conference, Bahrain, 11–14 March. The Ghawar field in eastern Saudi Arabia contains carbonate reservoirs. Most wells in the field produce from the Arab-D reservoir, an Upper Jurassic limestone sealed by anhydrite. Oil production from the field started approximately 55 years ago. Water injection started in the 1970s. A current evaluation of Arab-D wettability takes into account a long historical record of wettability measurements and production. The results of the original measurements have changed slightly, but they show a strong consistency 50 years later. Local variations in wettability indicating mixed wettability and oil-wet tendencies were observed when tar was present in a significant amount and in areas high on structure. Introduction The wetting properties of carbonate reservoirs are fundamental to the understanding of fluid flow in all aspects of oil production and can affect the production characteristics greatly during waterflooding. Therefore, knowledge of the preferential wettability of reservoir rock is of utmost importance. Carbonate reservoirs are heterogeneous in nature because of the wide spectrum of environments in which carbonates are deposited and the subsequent diagenetic alteration of the original rock fabric. These heterogeneities and the effects of wettability on residual-oil saturation, capillary pressure, electrical properties, relative permeability, and oil recovery encouraged research to characterize and evaluate wettability of carbonate reservoirs. In the past, many engineers assumed that most reservoir rocks were water-wet. Recent work showed many carbonate reservoirs are oil-wet. Other studies have shown that the wettability of carbonate rocks is oil-wet, neutral, or mixed. This paper summarizes a study of wettability for the Arab-D carbonate reservoir (Upper Jurassic) in Saudi Arabia. Arab-D Reservoir The Arab-D reservoir was discovered in 1948. Five additional areas were identified as parts of the Ghawar oil field. From north to south, they are Ain Dar, Shedgum, Uthmaniyah, Hawiyah, and Haradh. At the Arab-D level, the field is a north-northeast-trending composite anticline 230 km long by 30 km wide. The largest oil accumulations occur in the lowest grainstone cycle of the Arab formation, the Arab-D reservoir. The vertical oil column has a maximum thickness of 1,300 ft. The oil-saturated interval extends approximately 250 ft below the anhydrite that separates the Arab-D reservoir from overlying Arab-C carbonate beds. X-ray-diffraction and X-ray-fluorescence analyses revealed that the most predominant mineral in the Arab D reservoir is calcite (80–100 wt%), while dolomite constitutes a second minor mineral (0–26 wt%), along with trace amounts (<5 wt%) of quartz, pyrite, ankerite, and halite.

High-resolution characterization and integrated study of a reservoir formation: the danian carbonate platform in the Aquitaine Basin (France)

This paper provides an example of an integrated multi-scale study of a carbonate reservoir. The Danian Lower R2 carbonate reservoir is located in the South of the Aquitaine Basin (France) and represents a potential underground gas storage site for Gaz de France. The Danian Lower R2 reservoir was deposited as a prograding carbonate platform bordered by a reef barrier. The effects of sedimentary and diagenetic events on the reservoir properties, particularly dolomitization, were evaluated. In this study, the reservoir quality has been assessed by seismic analyses at the basin scale, by log-analysis at the reservoir scale, by petrographic methods and by petrophysical tools at the pore-core scale. Two dolomitization stages, separated by a compaction event with associated fracturing and stylolites, have been identified. These diagenetic events have significantly improved the Lower R2 carbonate reservoir properties. It is demonstrated that the reservoir quality is mainly controlled by the pore-geometry, which is determined by various diagenetic processes. The permeability values of the reservoir range over 4 orders of magnitude, from 0.1 to 5600 mD and the porosity values range between 2 and 42%. Reservoir unit 4 (a karstic dolomite) shows the best reservoir properties with average porosity values ranging between 11.1% and 19.3% and an average permeability ranging between 379 and 766 mD. Reservoir unit 2 (a fine-grained limestone) shows the worst reservoir properties. The cementation factors range from 1.68 to 2.48. The dolomitic crystal carbonate texture (mainly units 3 and 4) shows the highest value of the cementation factor (1.98–2.48) and formation factor (9.54–36.97), which is due to its high degree of cementation. The saturation exponents vary between 1.2 and 3.4. Using these experimental electrical parameters and the resistivity laterolog tool we predicted the water saturation in the various reservoir units. The permeability was predicted by combining the formation factor with the micro-geometric characteristic length. The best fit is obtained with the Katz and Thompson's model and for a constant of 1/171.

Abstract: Integrating Plug to Well-scale Petrophysics with Detailed Sedimentology to Quantify Fracture, Vug and Matrix Properties in Carbonate Reservoirs: An Example from the Arbuckle Group, Kansas 

Abstract: Integrating Plug to Well-scale Petrophysics with Detailed Sedimentology to Quantify Fracture, Vug and Matrix Properties in Carbonate Reservoirs: An Example from the Arbuckle Group, Kansas 

Facies Control of Carbonate Reservoir Properties: ABSTRACT

The relation between the depositional and diagenetic facies within a carbonate reservoir may affect the success of a secondary-recovery project in terms of the residual oil saturation following displacement of oil by water. Recognition of facies control on the evolution of porosity and permeability aids in the prediction of reservoir performance. Displacement tests, performed on vugular carbonate cores, illustrate this point. Strongly wetting countercurrent imbibition tests, conducted on full-diameter cores from the Meekwap field in Alberta, reveal the effects of secondary porosity on the displacement of a nonwetting oil phase. In Amphipore sp. wackestones, dolomitization and dissolution of Amphipore segments have produced a random distribution of small moldic pores that are matrix connected. During water-wet displacement tests, poor displacement efficiency is realized in the high moldic porosity wackestones. Visual observations indicate that the nonwetting oil phase is preferentially trapped in the moldic pores. Reef-core boundstones, composed of a laminar stromatoporoid and algal assemblage, have a pore structure dominated by tabular vugs linked by vertical fractures. In contrast to the moldic pore syste , displacement efficiency is maximized in the high porosity intervals as buoyancy forces allow oil to migrate through the vug-fracture system. Visual differentiation of the end-member pore systems will allow the development of a reservoir model that can predict oil recovery within various depositional facies within the reservoir. End_of_Article - Last_Page 621------------