Carboniferous Carbonate Reservoirs Research Articles

A rapid optimization methodology of produced gas reinjection EOR in carbonate reservoirs

The Carboniferous carbonate reservoir of the Pre-Caspian basin has abundant oil and gas resources. The typical features of low porosity and low permeability and reservoir oil with high concentrations of H2S and CO2 and heavily dissolved gas-oil ratio allow produced gas reinjection as an effective and economic way to enhance oil recovery (EOR). However, the optimal design of injection/production parameters for gas injection processes is the premise for development scheme and technical decision. Compared to the conventional method of one-parameter-at-a-time approach with lack of interactions between various factors and tremendous challenge of main controlling factors identified, in this work we present a rapid optimization methodology to identify the main factors from numerous candidate parameters and obtain optimum levels of key factors. Our chosen methodology is a combination of experimental design with response surface method (RSM). Firstly, the two-level Plackett-Burman experimental design was used to screen and rank ten operational variables for the gas reinjection process. The top five significant parameters with the sum of their influencing weight greater than 94.3 % are bottomhole pressure for producers, reinjection ratio, injection period, injection gas timing and completion interval. Then the three-level Box-Behnken experimental design was employed to perform optimization exploration with the RSM. Regression models of the oil recovery factor (RF) were constructed by using these five key factors, which fits excellently with numerical simulation results. Finally, the optimal levels of controlling factors were determined to maximize oil recovery. This optimization procedure is very practical for reservoir engineers to guide a rapid evaluation of gas injection processes.

Evaluation of pore-throat structures of carbonate reservoirs based on petrophysical facies division

After complex geological transformation, such as sedimentation, diagenesis, and tectonic transformation, carbonate reservoirs have developed multiple reservoir spaces with significant heterogeneity and various pore-throat structures, including pores, vugs, and fractures. Due to these characteristics, many problems have been caused during the development of carbonate reservoirs, such as large differences between the initial production capacities of single wells and serious water channeling after injection, which have brought many challenges to the efficient development of carbonate reservoirs. Therefore, based on a reservoir evaluation method of petrophysical facies, this study classified and evaluated the pore-throat structures of Carboniferous carbonate reservoirs in the North Truwa oilfield of the Pre-Caspian Basin. Based on the data of the core, thin section, scanning electron microscope, high-pressure mercury injection, sedimentary facies, diagenetic facies, and the development of fractures and karst vugs, six reservoir petrophysical facies in the study area were classified and named, including the facies of favorable sedimentation-constructive diagenesis-fracture and vug, the facies of favorable sedimentation-constructive diagenesis-non-fracture or vug, the facies of favorable sedimentation-destructive diagenesis-fracture and vug, the facies of favorable sedimentation-destructive diagenesis-non-fracture or vug, the facies of unfavorable sedimentation-constructive diagenesis-non-fracture or vug, and the facies of unfavorable sedimentation-destructive diagenesis-non-fracture or vug. The recognition and division of diagenetic facies were based on the K-nearest neighbor. Four quantitative parameters were also selected to characterize the pore-throat structures, including displacement pressure (Pd), mercury removal efficiency (Em), median throat radius (R50), and sorting coefficient (Cs). Based on the principal component analysis, the classification and evaluation standards of pore-throat structures in different petrophysical facies were established. Combined with the flow profile measured by production logging tools, the relationship between different petrophysical facies and productions was also revealed. As a result, this study can provide suggestions for the adjustment strategy of water-driven production, which lays an important foundation for the fine development of carbonate reservoirs.

Characterization and Evaluation of Carbonate Reservoir Pore Structure Based on Machine Learning

The carboniferous carbonate reservoirs in the North Truva Oilfield have undergone complex sedimentation, diagenesis and tectonic transformation. Various reservoir spaces of pores, caves and fractures, with strong reservoir heterogeneity and diverse pore structures, have been developed. As a result, a quantitative description of the pore structure is difficult, and the accuracy of logging identification and prediction is low. These pose a lot of challenges to reservoir classification and evaluation as well as efficient development of the reservoirs. This study is based on the analysis of core, thin section, scanning electron microscope, high-pressure mercury injection and other data. Six types of petrophysical facies, PG1, PG2, PG3, PG4, PG5, and PG6, were divided according to the displacement pressure, mercury removal efficiency, and median pore-throat radius isobaric mercury parameters, combined with the shape of the capillary pressure curve. The petrophysical facies of the wells with mercury injection data were divided accordingly, and then the machine learning method was applied. The petrophysical facies division results of two mercury injection wells were used as training samples. The artificial neural network (ANN) method was applied to establish a training model of petrophysical facies recognition. Subsequently, the prediction for the petrophysical facies of each well in the oilfield was carried out, and the petrophysical facies division results of other mercury injection wells were applied to verify the prediction. The results show that the overall coincidence rate for identifying petrophysical facies is as high as 89.3%, which can be used for high-precision identification and prediction of petrophysical facies in non-coring wells.

Micropore Structures and Percolation Characteristics of Carboniferous Carbonate Reservoirs in the Zanarol Area.

Proven oil and gas reserves in carbonate rocks comprise a high proportion of oil and gas fields, but these reservoirs have high heterogeneity. It is of great importance to study the micropore structures and percolation characteristics of carbonate rocks for the development of oilfields. In this paper, reservoirs are studied by means of casting sections, high-pressure mercury injection, and water and gas flooding oil phase permeability experiments. Reservoirs are classified into three categories, I, II, and III, by the k-means cluster analysis method. The results show that class I reservoirs are mainly composed of biolimestone with strong dissolution, displacement pressure of 0.016 MPa, median pressure of 0.135 MPa, mercury removal efficiency of 17.15%, well-developed pore throats, and good connectivity. They have the highest reservoir quality index and strong percolation ability. Class II reservoirs are mainly biogenic limestone and granular limestone with intergranular pores, a displacement pressure of 0.098 MPa, a median pressure of 6.026 MPa, and a mercury removal efficiency of 25.82%. The pore throat class is complex, and the sorting is poor. Class III reservoirs are mainly clastic limestone with residual intergranular pores, poor connectivity, displacement pressure of 0.403 MPa, median pressure of 3.77 MPa, mercury removal efficiency of 14.01%, small median radii, and good sorting performance. Relative permeability experiments show that water drive permeability at the isopermeability point is (0.049 10–3 μm2) higher than that of gas drive (0.041 10–3 μm2). The permeability of oil and water phases in class I reservoirs is obviously higher than those of class II and III reservoirs. When gas flooding is used, the phase permeability characteristics of class I and II reservoirs are no different than when water flooding is used. The permeability of gas flooding is slightly lower than that of water flooding. Because of the high proportion of micropores in class III reservoirs, gas can easily enter the pores, so the relative permeability of the gas phase increases rapidly. With increases in injection volume, the ultimate oil displacement efficiency of class I reservoirs can reach 53.2%, while those of class II and III reservoirs are 50.7 and 46.1%, respectively. This study provides important guidance for formulating oilfield development plans.

Pore-throat structure characteristics and its impact on the porosity and permeability relationship of Carboniferous carbonate reservoirs in eastern edge of Pre-Caspian Basin

Abstract Carboniferous carbonate reservoirs at the eastern edge of the Pre-Caspian Basin have undergone complex sedimentation, diagenesis and tectonism processes, and developed various reservoir space types of pores, cavities and fractures with complicated combination patterns which create intricate pore-throats structure. The complex pore-throat structure leads to the complex porosity-permeability relationship, bringing great challenges for classification and evaluation of reservoirs and efficient development. Based on the comprehensive analysis on cores, thin sections, SEM, mercury intrusion, routine core analysis and various tests, this paper systematically investigated the features and main controlling factors of pore-throats structure and its impact on the porosity-permeability relationship of the four reservoir types which were pore-cavity-fracture, pore-cavity, pore-fracture and pore, and three progresses are made. (1) A set of classification and descriptive approach for pore-throat structure of Carboniferous carbonate reservoirs applied to the eastern edge of the Pre-Caspian Basin was established. Four types of pore-throat structures were developed which were wide multimodal mode, wide bimodal mode, centralized unimodal mode and asymmetry bimodal mode, respectively. The discriminant index of pore-throat structure was proposed, realizing the quantitative characterization of pore-throat structure types. (2) The microscopic heterogeneity of pore reservoir was the strongest and four types of pore-throat structures were all developed. The pore-fracture and pore-cavity-fracture reservoirs took the second place, and the microscopic heterogeneity of pore-cavity reservoir was the weakest. It was revealed that the main controlling factor of pore-throat structure was the combination patterns of reservoir space types formed by sedimentation, diagenesis and tectonism. (3) It was revealed that the development of various pore-throat structure types was the important factor affecting poroperm relationship of reservoirs. The calculation accuracy of permeability of reservoirs can be improved remarkably by subdividing the pore-throat structure types. This study deepens the understanding of pore-throat structure of complicated carbonate reservoirs, and is conducive to classification and evaluation, establishment of precise porosity-permeability relationship and highly efficient development of carbonate reservoirs.

An evaluation on mechanisms of miscibility development in acid gas injection for volatile oil reservoirs

Produced gas containing the acid gas reinjection is one of the effective enhanced oil recovery methods, not only saving costs of disposing acid gases and zero discharge of greenhouse gases but also supporting reservoir pressure. The subsurface fluid from the Carboniferous carbonate reservoir in the southern margin of the Pre-Caspian basin in Central Asia has low density, low viscosity, high concentrations of H2S (15%) and CO2 (4%), high solution gas/oil ratio. The reservoir is lack of fresh water because of being far away onshore. Pilot test has already been implemented for the acid gas reinjection. Firstly, in our work a scheme of crude oil composition grouping with 15 compositions was presented on the basis of bottomhole sampling from DSTs of four wells. After matching PVT physical experiments including viscosity, density and gas/oil ratio and pressure–temperature (P–T) phase diagram by tuning critical properties of highly uncertain heavy components, the compositional model with phase behavior was built under meeting accuracy of phase fitting, which was used to evaluate mechanism of miscibility development in the acid gas injection process. Then using a cell-to-cell simulation method, vaporizing and/or condensing gas drive mechanisms were investigated for mixtures consisting of various proportions of CH4, CO2 and H2S in the gas injection process. Moreover, effects of gas compositions on miscible mechanisms have also been determined. With the aid of pressure-composition diagrams and pseudoternary diagrams generated from the Equation of State (EoS), pressures of First Contact Miscibility (FCM) and Multiple Contact Miscibility (MCM) for various gases mixing with the reservoir oil sample under reservoir temperature were calculated. Simulation results show that pressures of FCM are higher than those of MCM, and CO2 and H2S are able to reduce the miscible pressure. At the same time, H2S is stronger. As the CH4 content increases, both pressures of FCM and MCM are higher. But incremental values of MCM decrease. In addition, calculated envelopes of pseudoternary diagrams for mixtures of CH4, CO2 and H2S gases of varying composition with acid gas injection have features of bell shape, hourglass shape and triangle shape, which can be used to identify vaporizing and/or condensing gas drives. Finally, comparison of the real produced gas and the one deprived of its C3+ was performed to determine types of miscibility and calculate pressures of FCM and MCM. This study provides a theoretical guideline for selection of injection gas to improve miscibility and oil recovery.

Petrophysical Characterization and Fractal Analysis of Carbonate Reservoirs of the Eastern Margin of the Pre-Caspian Basin

Petrophysical properties including pore structure and permeability are essential for successful evaluation and development of reservoirs. In this paper, we use casting thin section and mercury intrusion capillary pressure (MICP) data to investigate the pore structure characterization, permeability estimation, and fractal characteristics of Carboniferous carbonate reservoirs in the middle blocks of the eastern margin of the Pre-Caspian Basin. Rock casting thin sections show that intergranular and intragranular dissolution pores are the main storage spaces. The pore throats greater than 1 μm and lower than 0.1 μm account for 47.98% and 22.85% respectively. A permeability prediction model was proposed by incorporating the porosity, Swanson, and R35 parameters. The prediction result agrees well with the core sample data. Fractal dimensions based on MICP curves range from 2.29 to 2.77 with an average of 2.61. The maximum mercury intrusion saturation is weakly correlated with the fractal dimension, while the pore structure parameters such as displacement pressure and median radii have no correlation with fractal dimension, indicating that single fractal dimension could not capture the pore structure characteristics. Finally, combined with the pore types, MICP shape, and petrophysical parameters, the studied reservoirs were classified into four types. The productivity shows a good correlation with the reservoir types.

Pore structure and fractal analysis of Lower Carboniferous carbonate reservoirs in the Marsel area, Chu-Sarysu basin

Abstract Evaluation of carbonate heterogeneity, closely related to pore geometry and connectivity, is important in oil and gas field production and reservoir prediction. To profoundly understand the heterogeneity of Lower Carboniferous carbonate reservoirs in the Marsel area, including Visean (C1v) and Serpukhovian (C1sr), the pore structure and fractal characteristics are investigated using routine petrophysical measurements, X-ray diffraction (XRD), cast thin section analysis, scanning electron microscopy (SEM), and mercury injection capillary pressure (MICP) tests. The origin of potentially prolific reservoir, the relationships between fractal dimension and reservoir physical properties, mineral composition and pore structure are also discussed. XRD results reveal that the mineral compositions are highly heterogeneous in C1v and C1sr. Routine petrophysical experiments indicate that C1v and C1sr are generally tight. However, some high porosity-permeability zones exist in C1sr, which is described as a potentially prolific reservoir. The cast thin section and SEM analyses identify three main pore types in the potentially prolific reservoir: interparticle dissolution pores, intercrystalline dissolution pores, and moldic pores. The MICP data reflect that the pore-throat radii in the prolific reservoir range from 0.29 to 4.6 μm, whereas those in tight section are typically

Distribution patterns of main structural-group parameters of crude oils from the Volga–Urals oil and gas basin according to NMR data

The character of the distribution of 16 main NMR-measurable parameters of the structural-group composition of Volga–Urals crude oils has been assessed. It has been shown that the distributions quite significantly differ from the normal distribution; they are in general asymmetrical and essentially different. Total aromaticity and the amount of n-alkyl structures in oils of the major stratigraphic plays are on average the same, although there are differences between the northern, central, and southern parts of the oil-and-gas basin. Regarding the concentration of unsaturated hydrocarbons, there are differences between both the plays and territories. Similarities and dissimilarities between the West Siberian and Volga–Urals basins in distributions have been revealed. Some features observed for Western Siberia oils have to be other in the Volga–Urals basin. Upper Carboniferous and Lower Permian carbonate reservoirs in the northeast of the basin have been found to contain oils with a uniquely high concentration of aromatics that evidently differ in composition from those normally present in crude oils. The advantages of interval plots of probability density over histograms for comparing the distributions have been demonstrated. Using the particular material, it has been shown that the Student t-test conventionally used to compare average values for oil groups leads to false conclusions. To determine systematic shifts between distributions, it is necessary to use the Mann–Whitney test and compare the medians of distributions.

Methods to analyse fracture orientation patterns in a Lower Carboniferous carbonate reservoir analogue in the Voreifel, Germany

We studied in a highly fractured Lower Carboniferous carbonate quarry close to Hastenrath (Voreifel, Germany) that provides a good analogue to a fractured carbonate reservoir, two modern techniques to collect data on fracture orientation semi-automatically in the field, and compared them to the results of traditional fracture measurements. Firstly, fractures were measured along several scanlines using a traditional compass and a modern application on an Android smartphone. Overall, the smartphone measurements reflect the same orientation as traditional compass measurements but generate in the same time a much higher number of data. Secondly, terrestrial laser scanning (TLS) was used to measure and visualise the topographic relief of the quarry walls down to centimetre resolution for close-up digital analysis of fractures. With this method, we were able to identify the same fracture groups as identified in the manually measured scanlines. All measurements indicate two dominant NE‒SW and NW‒SE striking fracture sets, regardless of the technique. An additional W‒E striking set is indicated immediately in the footwall of the Sandgewand Fault. Furthermore, fault-related fracturing is indicated by an increase of fracture densities towards the Sandgewand Fault. In addition to the fractures, minor NW‒SE striking faults were also observed in the Hastenrath quarry, some with tens of metres of displacement. Locally horizontal slickensides overprint earlier down-slip movement. Based on dextral slickensides on these fault surfaces oriented parallel to the large Sandgewand Fault, we assume that the latter also had a late dextral strike-slip motion component. Based on the results presented in this paper, we conclude that smartphone measurements of fractures and terrestrial laser scanning are appropriate tools to analyse fracture networks in reservoir analogues in a rapid and accurate way. Kurzfassung: Im Rahmen dieser Studie wurden in einem stark geklufteten Kohlenkalk-Steinbruch nahe Hastenrath (Voreifel, Deutschland) zwei moderne Methoden zum semi-automatischen Erfassen von Kluftorientierungen im Gelande untersucht und mit traditionellen Methoden der Kluftmessung verglichen. Die Orientierungen der Klufte entlang mehrerer Scanlinien wurden dazu zunachst traditionell mit einem Gefugekompass und im Anschluss mit Hilfe einer modernen Smartphone-Applikation auf Android-Basis ermittelt. Beide Messmethoden zeigen eine gute Ubereinstimmung der Kluftvorzugsorientierungen, unterschieden sich allerdings stark in der fur die Messung benotigten Zeit. Daruber hinaus wurden Teile des Steinbruchs unter Anwendung eines modernen Terrestrial Laser Scanners (TLS) semiautomatisch vermessen. Moderne TLS sammeln innerhalb kurzester Zeit hochauflosende digitale Abbilder zu untersuchender Objekte, auch an schwer oder nicht zuganglichen Orten, wodurch im Steinbruch auch von unzuganglichen und somit bei traditioneller Kartierung sonst nicht einmessbaren Stellen, Messwerte ermittelt werden konnten. Ein Vergleich der mit dieser Technik ermittelten Messwerte zu den manuell ermittelten Gefugemessungen zeigt vergleichbare Kluftvorzugsrichtungen. Die Messungen im Hastenrather Steinbruch zeigen unabhangig von der Messmethode zwei dominante NE‒SW bzw. NW‒SE streichende Kluftsysteme. Zusatzlich zu den oben genannten Kluftsystemen konnte in unmittelbarer Nahe zur © 2014 E. Schweizerbart’sche Verlagsbuchhandlung, Stuttgart, Germany DOI: 10.1127/1860-1804/2014/0078 www.schweizerbart.de 1860-1804/0078 $ 5.40 Z. Dt. Ges. Geowiss. (German J. Geosci.), 165 (3), p. 319–330, 5 figs. Article Stuttgart, September 2014

川东地区石炭系碳酸盐岩储层成因机理及主控因素研究

世界上碳酸盐岩储层的油气产量约占世界油气总产量的60%，但是在我国，与常规的砂岩油气藏相比，碳酸盐岩油气藏勘探开发程度较低，所以研究碳酸盐岩储层具有重大的实际意义。本文通过对川东地区石炭系碳酸盐岩储层成因机理及主控因素的研究，深刻地剖析其储层形成机理，有利于该区碳酸盐岩储层的评价与预测，为油气开采提供了重要的地质依据。在总结前人研究成果的基础上，重点从影响储层形成的主控因素——沉积相与岩性对储层发育的控制，白云岩化的作用和古岩溶作用对储层发育的控制进行了描述，以及对各个成岩阶段，不同主控因素对储层形成的机理进行了动态分析。The production of oil and gas generated from the carbonatite reservoirs makes up 60 percent of the total oil and gas production in the world. But the exploration degree of the carbonatite reservoir is relatively lower compared with that of the conventional sandstone reservoirs in China. So the research for the carbonatite reservoir rocks has a great significance. In this paper, the formation mechanism and the main control factors for the formation mechanism of the Carboniferous carbonate reservoir rocks in eastern Sichuan area have been studied. The research on the forma-tion mechanism of the carbonatite reservoirs will be of benefit to the evaluation and prediction of the carbonatite reservoirs, and also will provide an important geological basis for the exploration of oil and gas in the study area. Based on the research of predecessors’ research findings, we focused on the description of the main control factors, including sedimentary facies and lithology, dolomitization and palaeo-karstification. In addition, we also analyzed the dynamic for the influence of various diagenetic stages and main control factors on the formation mechanism of the Carboniferous carbonate reservoir rocks in eastern Sichuan area.

Carbonate Depositional Facies Analysis and Reservoir Prediction for Central Block in Pre-Caspian Basin

In waveform classification for which abundant seismic data are fully used, neural network algorithm is applied to compare and classify the actual seismic waveforms by traces for one specific formation, so as to delineate the lateral variation of seismic signal in details and thus acquire the seismic facies maps corresponding to geologic characteristics. Moreover, through analysis of drilling data, logging data and depositional facies, the depositional facies belts are further divided for formation and lithologic reservoir prediction. Carbonate reservoir in the Central Block in the east margin of Pre-Caspian Basin is discussed as an example to introduce the application of waveform classification and depositional facies demarcation in the Carboniferous Carbonate reservoir. Favorable reservoir beds are also predicted, contributing to a big breakthrough for risk exploration in this area.

Study on Primary Controlling Factors to Carbonate Reservoir Physical Properties of Zhanazhol Oilfield

By the aid of such core analysis data as lithochemical data, physical property data, thin sections and capillary pressure curves, studies were made on the physical properties and its primary controlling factors of carboniferous carbonate reservoirs of Zhanazhol oilfield. The studies were focused on such aspects as lithology, void type, pore connectivity, developing degree of vugs and fractures and fracture type. The study shows that the reservoirs of KT-I are principally multiple void-typed with middle porosity and permeability, with lithology, developing degree of vugs and fractures and fracture type being the primary controlling factors to their physical properties, and that the reservoirs of KT-II are principally fracture-pore typed with low to middle porosity and permeability, with lithology, void type, pore connectivity and fracture type being the primary controlling factors.

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

AbstractThe IEA Weyburn Carbon Dioxide (CO2) Monitoring and Storage Project analysed the effects of a miscible CO2 flood into a Lower Carboniferous carbonate reservoir rock at an onshore Canadian oilfield. Anthropogenic CO2 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 CO2 and the effects of CO2 on the hydrochemical and mineralogical properties of the reservoir rock. The pre-CO2 injection hydrochemical, hydrogeological and petrographical conditions in the reservoir were investigated in order to recognize changes caused by the CO2 flood and to assess the long-term fate of the injected CO2. The Lower Carboniferous (Mississippian) aquifer has a salinity gradient in the Weyburn area, where flows are oriented SW–NE. Hydrogeological modelling indicates that dissolved CO2 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 CO2 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 CO2 and methane (CH4) increased significantly in the injection area between 2002 and 2003. Most of the injected CO2 exists in a supercritical state, lesser amounts are trapped in solution and there is little apparent mineral trapping. The CO2 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 CO2–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 CO2 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 CO2 in soil gases. Isotopic (δ13C) data values are higher than in the injected CO2, and confirm this interpretation. No evidence for leakage of the injected CO2 to ground level has been detected. The long-term safety and performance of CO2 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 CO2.

Abstract :Stratigraphic Correlation of Carboniferous Carbonate Reservoirs In the North-East Caspian Sea Region

Abstract :Stratigraphic Correlation of Carboniferous Carbonate Reservoirs In the North-East Caspian Sea Region