Oil Saturation Index in Hydrophobic Carbonate Reservoir: Evaluation Aspects

2021 ◽  
Author(s):  
Regina Khanbikova ◽  
Venera Bazarevskaya ◽  
Oleg Sotnikov ◽  
Albert Bachkov
Keyword(s):  
Carbonate Rocks ◽  
Carbonate Reservoir ◽  
Carbonate Reservoirs ◽  
Reservoir Rock ◽  
Western Slope ◽  
Void Space ◽  
The South ◽  
Reservoir Properties ◽  
Lower Carboniferous ◽  
Hydrocarbon Reserves

Abstract Hydrocarbon reserves in carbonate reservoirs account for 38% - 60% of total world reserves, according to different estimates. In Tatarstan, carbonate reservoirs are found, mostly, in the eastern slope of the Melekess Depression and the South-Tatarian Arch. The carbonate reservoirs are confined to the Middle and Lower Carboniferous sediments, the Upper Devonian (including the domanik sediments), and the Upper Permian (the Kazanian heavy oil accumulations). Considering an extensive geographic and stratigraphic range and differing tectonic and sedimentation environments, the carbonate rocks are characterized by a variety of reservoir properties. In contrast to terrigenous rocks, the carbonate void space is complicated by secondary processes that took place much later than the sedimentogenesis-lithogenesis stage. Numerous fissures, caves, sutures, and stylolites form the void space of the reservoir rock matrix containing commercial hydrocarbon reserves. In addition to fracturing and vugginess contributing to increase of void space of carbonate rocks, the secondary processes include sulphatisation and secondary dolomitization (in limestones), adding to deterioration of reservoir properties. The secondary processes impede understanding and evaluation of reservoir properties and saturation potential, in particular, determination of the oil and gas saturation factors (Dyakonova T.F. et al, 2019, Akhmetov R.T. et al, 2017)/ In the western slope of the South-Tatarian Arch, carbonate reservoirs are confined to the Middle and Lower Carboniferous sediments. Numerous RCAL and SCAL investigations provided valuable insight into these targets. In this paper, we used data from the laboratory experiments and studies of core and oil samples from the six neighbor fields on the western slope of the South-Tatarian Arch. Because of common sedimentological and tectonic sedimentation environments and lithological similarity of rocks within the stratigraphic referencing, the six fields under analysis were considered as analogous, and the results of the laboratory studies of the samples were reviewed collectively.

scholarly journals Reservoir Properties of Low-Permeable Carbonate Rocks: Experimental Features

Energies ◽  
2020 ◽  
Vol 13 (9) ◽  
pp. 2233 ◽  
Author(s):  
Aliya Mukhametdinova ◽  
Andrey Kazak ◽  
Tagir Karamov ◽  
Natalia Bogdanovich ◽  
Maksim Serkin ◽  
...  
Keyword(s):  
Gas Permeability ◽  
Total Porosity ◽  
Carbonate Reservoir ◽  
Reservoir Rock ◽  
Crushed Rock ◽  
Void Space ◽  
Reservoir Properties ◽  
Rock Samples ◽  
Liquid Saturation ◽  
Imaging Results

This paper presents an integrated petrophysical characterization of a representative set of complex carbonate reservoir rock samples with a porosity of less than 3% and permeability of less than 1 mD. Laboratory methods used in this study included both bulk measurements and multiscale void space characterization. Bulk techniques included gas volumetric nuclear magnetic resonance (NMR), liquid saturation (LS), porosity, pressure-pulse decay (PDP), and pseudo-steady-state permeability (PSS). Imaging consisted of thin-section petrography, computed X-ray macro- and microtomography, and scanning electron microscopy (SEM). Mercury injection capillary pressure (MICP) porosimetry was a proxy technique between bulk measurements and imaging. The target set of rock samples included whole cores, core plugs, mini cores, rock chips, and crushed rock. The research yielded several findings for the target rock samples. NMR was the most appropriate technique for total porosity determination. MICP porosity matched both NMR and imaging results and highlighted the different effects of solvent extraction on throat size distribution. PDP core-plug gas permeability measurements were consistent but overestimated in comparison to PSS results, with the difference reaching two orders of magnitude. SEM proved to be the only feasible method for void-scale imaging with a spatial resolution up to 5 nm. The results confirmed the presence of natural voids of two major types. The first type was organic matter (OM)-hosted pores, with dimensions of less than 500 nm. The second type was sporadic voids in the mineral matrix (biogenic clasts), rarely larger than 250 nm. Comparisons between whole-core and core-plug reservoir properties showed substantial differences in both porosity (by a factor of 2) and permeability (up to 4 orders of magnitude) caused by spatial heterogeneity and scaling.

Decision Criterion for Acid-Stimulation Method in Carbonate Reservoirs: Matrix Acidizing or Acid Fracturing?

SPE Journal ◽  
2020 ◽  
Vol 25 (05) ◽  
pp. 2296-2318
Author(s):  
Mateus Palharini Schwalbert ◽  
Murtada Saleh Aljawad ◽  
Alfred Daniel Hill ◽  
Ding Zhu
Keyword(s):  
Decision Criterion ◽  
Carbonate Reservoir ◽  
Carbonate Reservoirs ◽  
Reservoir Rock ◽  
Dimensionless Number ◽  
Confining Stress ◽  
Reservoir Properties ◽  
Matrix Acidizing ◽  
Acid Fracturing ◽  
Stimulation Method

Summary Most wells in carbonate reservoirs are stimulated. Because of their low cost and simpler operations, acid-stimulation methods are usually preferred if they are sufficient. Matrix acidizing can effectively stimulate carbonate reservoirs, often resulting in skin factors on the order of −3 to −4. In low confining stress and hard rocks, acid fracturing can yield better results than matrix acidizing. However, acid fracturing is less effective in high permeability, high confining stress, or soft rocks. There is a combination of parameters, among them permeability, confining stress, and rock geomechanical properties, that can be used as criteria to decide whether matrix acidizing or acid fracturing is the best acid-stimulation technique for a given scenario. This study compares the productivity of matrix-acidized and acid-fractured wells in carbonate reservoirs. The criterion used to decide the preferred method is the largest productivity obtained using the same volume of acid for both operations. The productivity of the acid-fractured wells is estimated using a fully coupled acid-fracturing simulator, which integrates the geomechanics (fracture propagation), pad and acid transport, heat transfer, temperature effect on reaction rate, effect of wormhole propagation on acid leakoff, and finally calculates the well productivity by simulating the flow in the reservoir toward the acid fracture. Using this simulator, the acid-fracturing operation is optimized, resulting in the operational conditions (injection rate, type of fluid, amount of pad, and so forth) that lead to the best possible acid fracture that can be created with a given amount of acid. The productivity of the matrix-acidized wells is estimated using the most recent wormhole-propagation models scaled up to field conditions. Results are presented for different types of rock and reservoir scenarios, such as shallow and deep reservoirs, soft and hard limestones, chalks, and dolomites. Most of the presented results considered vertical wells. A theoretical extension to horizontal wells is also presented using analytical considerations. For each type of reservoir rock and confining stress, there is a cutoff permeability less than which acid fracturing results in a more productive well; at higher than this cutoff permeability, matrix acidizing should be preferred. This result agrees with the general industry practice, and the estimated productivity agrees with the results obtained in the field. However, the value of the cutoff permeability changes for each case, and simple equations for calculating it are presented. For example, for harder rocks or shallower reservoirs, acid fracturing is more efficient up to higher permeabilities than in softer rocks or at deeper depths. This method provides an engineered criterion to decide the best acid-stimulation method for a given carbonate reservoir. The decision criterion is presented for several different scenarios. A simplified concise analytical decision criterion is also presented: a single dimensionless number that incorporates all pertinent reservoir properties and determines which stimulation method yields the most productive well, without needing any simulations.

scholarly journals Formation environments and mechanisms of multistage paleokarst of Ordovician carbonates in Southern North China Basin

2021 ◽  
Vol 11 (1) ◽  
Author(s):  
Haitao Zhang ◽  
Guangquan Xu ◽  
Mancai Liu ◽  
Minhua Wang
Keyword(s):  
Carbonate Rocks ◽  
North China ◽  
Oil And Gas ◽  
Carbonate Reservoir ◽  
Carbonate Reservoirs ◽  
Geochemical Data ◽  
Near Surface ◽  
Oil And Gas Exploration ◽  
Pore Types ◽  
North China Basin

AbstractWith the reduction of oil and gas reserves and the increase of mining difficulty in Northern China, the carbonate rocks in Southern North China Basin are becoming a significant exploration target for carbonate reservoirs. However, the development characteristics, formation stages, formation environments and mechanisms of the carbonate reservoirs in Southern North China Basin are still unclear, which caused the failures of many oil and gas exploration wells. This study focused on addressing this unsolved issue from the Ordovician carbonate paleokarst in the Huai-Fu Basin, which is located in the southeast of Southern North China Basin and one of the key areas for oil and gas exploration. Based on petrology, mineralogy and geochemical data, pore types, distribution characteristics, and formation stages of the Ordovician paleokarst were analyzed. Then, in attempt to define the origins of porosity development, the formation environments and mechanisms were illustrated. The results of this study showed that pore types of the Ordovician carbonates in the Huai-Fu Basin are mainly composed of intragranular pores, intercrystalline (intergranular) pores, dissolution pores (vugs), fractures, channels, and caves, which are usually in fault and fold zones and paleoweathering crust. Furthermore, five stages and five formation environments of the Ordovician paleokarst were identified. Syngenetic karst, eogenetic karst, and paleoweathering crust karst were all developed in a relatively open near-surface environment, and their formations are mainly related to meteoric water dissolution. Mesogenetic karst was developed in a closed buried environment, and its formation is mainly related to the diagenesis of organic matters and thermochemical sulfate reduction in the Permian-Carboniferous strata. Hydrothermal (water) karst was developed in a deep-buried and high-temperature environment, where hydrothermal fluids (waters) migrated upward through structures such as faults and fractures to dissolve carbonate rocks and simultaneously deposited hydrothermal minerals and calcites. Lastly, a paleokarst evolution model, combined with the related porosity evolution processes, nicely revealed the Ordovician carbonate reservoir development. This study provides insights and guidance for further oil and gas exploration in the Southern North China Basin, and also advances our understanding of the genesis of carbonate paleokarst around the world.

Using Logging and Seismic Data to Identify Boundaries Between Different OWC Units in a Deepwater Carbonate Reservoirs

2021 ◽  
Author(s):  
Kangxu Ren ◽  
Junfeng Zhao ◽  
Jian Zhao ◽  
Xilong Sun
Keyword(s):  
Seismic Data ◽  
Carbonate Rocks ◽  
Carbonate Reservoir ◽  
Carbonate Reservoirs ◽  
Sedimentary Process ◽  
Core Samples ◽  
Tight Carbonate ◽  
Porosity And Permeability ◽  
Seismic Sections ◽  
Parameters Inversion

Abstract At least three very different oil-water contacts (OWC) encountered in the deepwater, huge anticline, pre-salt carbonate reservoirs of X oilfield, Santos Basin, Brazil. The boundaries identification between different OWC units was very important to help calculating the reserves in place, which was the core factor for the development campaign. Based on analysis of wells pressure interference testing data, and interpretation of tight intervals in boreholes, predicating the pre-salt distribution of igneous rocks, intrusion baked aureoles, the silicification and the high GR carbonate rocks, the viewpoint of boundaries developed between different OWC sub-units in the lower parts of this complex carbonate reservoirs had been better understood. Core samples, logging curves, including conventional logging and other special types such as NMR, UBI and ECS, as well as the multi-parameters inversion seismic data, were adopted to confirm the tight intervals in boreholes and to predicate the possible divided boundaries between wells. In the X oilfield, hundreds of meters pre-salt carbonate reservoir had been confirmed to be laterally connected, i.e., the connected intervals including almost the whole Barra Velha Formation and/or the main parts of the Itapema Formation. However, in the middle and/or the lower sections of pre-salt target layers, the situation changed because there developed many complicated tight bodies, which were formed by intrusive diabase dykes and/or sills and the tight carbonate rocks. Many pre-salt inner-layers diabases in X oilfield had very low porosity and permeability. The tight carbonate rocks mostly developed either during early sedimentary process or by latter intrusion metamorphism and/or silicification. Tight bodies were firstly identified in drilled wells with the help of core samples and logging curves. Then, the continuous boundary were discerned on inversion seismic sections marked by wells. This paper showed the idea of coupling the different OWC units in a deepwater pre-salt carbonate play with complicated tight bodies. With the marking of wells, spatial distributions of tight layers were successfully discerned and predicated on inversion seismic sections.

SECONDARY CHANGES IN CARBONATE ROCKS OF OIL AND GAS COMPLEXES

2020 ◽  
pp. 18-23
Author(s):  
M.A. Tugarova
Keyword(s):  
Carbonate Rocks ◽  
Oil And Gas ◽  
Carbonate Reservoirs ◽  
Fundamental Importance ◽  
Schematic Diagram ◽  
Reservoir Properties ◽  
Physico Chemical ◽  
Chemical Conditions ◽  
First Time

The article considers the secondary transformations of carbonate rocks of oil and gas complexes, which are of fundamental importance in the formation of reservoir properties. For the first time, a schematic diagram, illustrating the regularities of secondary processes in carbonate reservoirs and their relationship with the physico-chemical conditions of the stratosphere is proposed.

scholarly journals Classification of Void Space Types in Fractured-Vuggy Carbonate Reservoir Using Geophysical Logging: A Case Study on the Sinian Dengying Formation of the Sichuan Basin, Southwest China

Energies ◽  
2021 ◽  
Vol 14 (16) ◽  
pp. 5087
Author(s):  
Kunyu Wang ◽  
Juan Teng ◽  
Hucheng Deng ◽  
Meiyan Fu ◽  
Hongjiang Lu
Keyword(s):  
Sichuan Basin ◽  
Southwest China ◽  
Carbonate Reservoir ◽  
Carbonate Reservoirs ◽  
Void Space ◽  
Identification Method ◽  
Geophysical Logging ◽  
Dengying Formation ◽  
Porosity And Permeability ◽  
Core Description

The fractured-vuggy carbonate reservoirs display strong heterogeneity and need to be classified into different types for specific characterization. In this study, a total of 134 cores from six drilled wells and six outcrops of the Deng #2 and Deng #4 members of the Dengying Formation (Sichuan Basin, Southwest China) were selected to investigate the petrographic characteristics of void spaces in the fractured-vuggy carbonate reservoirs. Four void space types (VSTs) were observed, namely the solution-filling type (SFT), cement-reducing type (CRT), solution-filling breccia type (SFBT) and solution-enlarging fractures and vugs type (SEFVT). The CRT void spaces presented the largest porosity and permeability, followed by the SEFVT, SFBT and SFT. The VSTs presented various logging responses and values, and based on these, an identification method of VSTs using Bayes discriminant analysis (BDA) was proposed. Two test wells were employed for the validation of the identification method, and the results show that there is good agreement between the identification results and core description. The vertical distribution of VSTs indicates that the SFT and SEFVT are well distributed in both the Deng #2 and Deng #4 members. The CRT is mainly found in the Deng #2 member, and the SFBT occurs in the top and middle of the Deng #4 member.

scholarly journals A Practical Method to Calculate and Model the Petrophysical Properties of Reservoir Rock Using Petrel Software: A case Study from Iraq

2020 ◽  
pp. 2640-2650
Author(s):  
Sarah Taboor Wali ◽  
Hussain Ali Baqer
Keyword(s):  
Water Saturation ◽  
Three Dimensional ◽  
Carbonate Reservoir ◽  
Reservoir Rock ◽  
Sequential Gaussian Simulation ◽  
Geological Model ◽  
Petrophysical Properties ◽  
Reservoir Properties ◽  
Software Models ◽  
Average Water

Nasiriyah oilfield is located in the southern part of Iraq. It represents one of the promising oilfields. Mishrif Formation is considered as the main oil-bearing carbonate reservoir in Nasiriyah oilfield, containing heavy oil (API 25o(. The study aimed to calculate and model the petrophysical properties and build a three dimensional geological model for Mishrif Formation, thus estimating the oil reserve accurately and detecting the optimum locations for hydrocarbon production. Fourteen vertical oil wells were adopted for constructing the structural and petrophysical models. The available well logs data, including density, neutron, sonic, gamma ray, self-potential, caliper and resistivity logs were used to calculate the petrophysical properties. The interpretations and environmental corrections of these logs were performed by applying Techlog 2015 software. According to the petrophysical properties analysis, Mishrif Formation was divided into five units (Mishrif Top, MA, shale bed, MB1 and MB2).    A three-dimensional geological model, which represents an entrance for the simulation process to predict reservoir behavior under different hydrocarbon recovery scenarios, was carried out by employing Petrel 2016 software. Models for reservoir characteristics (porosity, permeability, net to gross NTG and water saturation) were created using the algorithm of Sequential Gaussian Simulation (SGS), while the variogram analysis was utilized as an aid to distribute petrophysical properties among the wells.      The process showed that the main reservoir unit of Mishrif Formation is MB1 with a high average porosity of 20.88% and a low average water saturation of 16.9%. MB2 unit has good reservoir properties characterized by a high average water saturation of 96.25%, while MA was interpreted as a water-bearing unit. The impermeable shale bed unit is intercalated between MA and MB1 units with a thickness of 5-18 m, whereas Mishrif top was interpreted as a cap unit. The study outcomes demonstrated that the distribution accuracy of the petrophysical properties has a significant impact on the constructed geological model which provided a better understanding of the study area’s geological construction. Thus, the estimated reserve h was calculated to be about 7945 MSTB. This can support future reservoir development plans and performance predictions. 

scholarly journals Carbonate reservoir rock typing algorithm based on integrated approach (IRT)

2021 ◽  
Vol 6 (4) ◽  
pp. 62-70
Author(s):  
Mariia A. Kuntsevich ◽  
Sergey V. Kuznetsov ◽  
Igor V. Perevozkin
Keyword(s):  
Water Saturation ◽  
Integrated Approach ◽  
Learning Technologies ◽  
Carbonate Reservoir ◽  
Reservoir Rock ◽  
Static Properties ◽  
Reservoir Properties ◽  
Optimal Method ◽  
Rock Types ◽  
Rock Typing

The goal of carbonate rock typing is a realistic distribution of well data in a 3D model and the distribution of the corresponding rock types, on which the volume of hydrocarbon reserves and the dynamic characteristics of the flow will depend. Common rock typing approaches for carbonate rocks are based on texture, pore classification, electrofacies, or flow unit localization (FZI) and are often misleading because they based on sedimentation processes or mathematical justification. As a result, the identified rock types may poorly reflect the real distribution of reservoir rock characteristics. Materials and methods. The approach described in the work allows to eliminate such effects by identifying integrated rock types that control the static properties and dynamic behavior of the reservoir, while optimally linking with geological characteristics (diagenetic transformations, sedimentation features, as well as their union effect) and petrophysical characteristics (reservoir properties, relationship between the porosity and permeability, water saturation, radius of pore channels and others). The integrated algorithm consists of 8 steps, allowing the output to obtain rock-types in the maximum possible way connecting together all the characteristics of the rock, available initial information. The first test in the Middle East field confirmed the applicability of this technique. Results. The result of the work was the creation of a software product (certificate of state registration of the computer program “Lucia”, registration number 2021612075 dated 02/11/2021), which allows automating the process of identifying rock types in order to quickly select the most optimal method, as well as the possibility of their integration. As part of the product, machine learning technologies were introduced to predict rock types based on well logs in intervals not covered by coring studies, as well as in wells in which there is no coring.

Low Polymer Retention Possible in Flooding of High-Salinity Carbonate Reservoirs

2021 ◽  
Vol 73 (11) ◽  
pp. 60-61
Author(s):  
Chris Carpenter
Keyword(s):  
Porous Medium ◽  
High Salinity ◽  
Material Balance ◽  
Synthetic Polymers ◽  
Polymer Flooding ◽  
Carbonate Reservoir ◽  
Carbonate Reservoirs ◽  
Reservoir Rock ◽  
Abu Dhabi ◽  
Polymer Retention

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202809, “Low Polymer Retention Opens for Field Implementation of Polymer Flooding in High-Salinity Carbonate Reservoirs,” by Arne Skauge, SPE, and Tormod Skauge, SPE, Energy Research Norway, and Shahram Pourmohamadi, Brent Asmari, et al., prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually 9–12 November. The paper has not been peer reviewed. Polymer flooding has been a successful enhanced-oil-recovery method in sandstone reservoirs for decades. Extending polymer flooding to carbonate reservoirs has been challenging because of adsorption loss and polymer availability for high-temperature, high-salinity (HT/HS) reservoirs. In this study, the authors establish that HT/HS polymers can exhibit low adsorption and retention in carbonate reservoir rock at ultrahigh salinity conditions. Introduction Retention is a key factor for polymer propagation and acceleration of oil production by polymer flooding. In the complete paper, the authors consider HT/HS applications for carbonate reservoirs. Synthetic polymers such as partially hydrolyzed polyacrylamide are not thermally stable at temperatures above 60°C. The thermal stability of the synthetic polymers can be improved by incorporating monomers. To evaluate the retention of polymer in reservoir rock, dynamic retention experiments were performed in the presence and absence of oil. In homogeneous rock, the presence of residual oil typically will reduce the retention proportional to the surface covered by the oil saturation. Strongly heterogeneous rock containing fractures also may have low retention because the fluid flow mainly may be through highly permeable fractures or channels and, consequently, only part of the porous medium will contact polymer. Retention in carbonate matrix displacement (homogeneous rock) was performed on outcrop Indiana limestone for reference, but most experiments were made on reservoir rock material. The polymer used is SAV 10. Experimental Methods The easiest and, in many cases, most-accurate method for quantifying retention in dynamic coreflow experiments is by material balance. This refers to the measurement of the polymer in the effluent. The injected amount minus the backproduced amount of polymer gives the loss caused by transport through the porous medium. The retention includes both adsorption of polymer onto the rock and dynamic loss as the result of mechanical entrapment such as molecular straining and concentration blocking. In most cases, the authors used a passive tracer injected with the polymer and applied two slugs. The first slug quantifies the retention by material balance, but the difference in effluent of the second slug minus the first slug also can give an alternative measurement of the polymer retention. Comparing tracer and polymer effluent concentrations from the second polymer slug quantifies the inaccessible pore volume (IPV). The experimental setup is illustrated in Fig. 1.

scholarly journals Liquid and Gas Corrected Permeability Correlation for Heterogeneous Carbonate Reservoir Rocks

2020 ◽  
pp. 36-50
Author(s):  
Sadonya Jamal Mustafa ◽  
Fraidoon Rashid ◽  
Khalid Mahmmud Ismail
Keyword(s):  
Gas Permeability ◽  
Carbonate Reservoir ◽  
Reservoir Rock ◽  
Reservoir Properties ◽  
Reservoir Rocks ◽  
Rock Types ◽  
Liquid Permeability ◽  
Porosity And Permeability ◽  
Permeability Distribution ◽  
Reservoir Type

Permeability is considered as an efficient parameter for reservoir modelling and simulation in different types of rocks. The performance of a dynamic model for estimation of reservoir properties based on liquid permeability has been widely established for reservoir rocks. Consequently, the validated module can be applied into another reservoir type with examination of the validity and applicability of the outcomes. In this study the heterogeneous carbonate reservoir rock samples of the Tertiary Baba Formation have been collected to create a new module for estimation of the brine permeability from the corrected gas permeability. In addition, three previously published equations of different reservoir rock types were evaluated using the heterogenous carbonate samples. The porosity and permeability relationships, permeability distribution, pore system and rock microstructures are the dominant factors that influenced on the limitation of these modules for calculating absolute liquid permeability from the klinkenberg-corrected permeability. The most accurate equation throughout the selected samples in this study was the heterogenous module and the lowest quality permeability estimation was derived from the sandstone module.

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