Author Correction: Study on discriminant method of rock type for porous carbonate reservoirs based on Bayesian theory

Abstract Trapped-gas saturations existing after gas displacement by wetting-phase imbibition are presented for selected carbonate reservoirs. presented for selected carbonate reservoirs. Formations representing various rock types were investigated, and samples covering the porosity and permeability range within each field were tested. Cores from Smackover reservoirs located within four states were included to examine differences in trapped gas that might occur within a carbonate deposited over a large geographical area. The trapped gas varied with initial gas in place and with rock type. With gas in place of 80 percent of pore space, trapped gas values ranged from a low of 23 percent of pore space in Type II chalk to a maximum of 69 percent in Type I limestone evaluated. Correlation of trapped-gas saturation values was attempted using several approaches, but none was entirely satisfactory. Essentially no relationship with permeability was found within most reservoirs or between different reservoirs. Within a given field, trapped gas at a common initial gas saturation typically increased as porosity decreased. A general interfield correlation with porosity was noted, but certain anomalous data were observed. Knowledge of rock type was necessary to explain these variations in trapped-gas saturations. It was concluded that the complexity of carbonates necessitates determination of trapped gas on the specific reservoir to be evaluated. Introduction Gas reservoirs with a naturally occurring underlying aquifer and aquifer gas storage projects both offer possibilities for large volumes of gas to be trapped and unrecovered. This trapping results from gas-water capillary forces that become active as production occurs and as water encroaches into pore space that previously contained interstitial pore space that previously contained interstitial water and gas. The magnitude of the trapped gas has been reported by others for sandstones, but essentially no information is available in the technical literature for carbonates. A series of carbonate reservoirs was studied to define the magnitude of trapped gas that existed for the range of porosity and permeability found within each reservoir. Trapped-gas saturation values were developed on each core for an initial gas saturation corresponding to irreducible water. Two cores from each reservoir were tested to yield additional trapped saturations for initial gas values of 20 and 50 percent of pore space. These additional data assist in defining trapped gas within a gas-water transition zone or within a gas storage aquifer where considerable variation in gas saturation may exist. Carbonate formations studied were selected to cover a range in pore geometry. Porosity and permeability were not sufficient to classify the permeability were not sufficient to classify the samples or correlate the data. Archie arrived at a classification of carbonate rocks based on the texture of the rock matrix and the nature of the visible pore structure. Table 1 is a summary of the classification, with slight modifications by Jodry. TABLE 1 - ARCHIE ROCK CLASSIFICATION Texture of Appearance of Appearance Under Matrix Hand Sample 10-Power Microscope Type I Crystalline, hard, dense Compact with smooth face on No visible pore space Crystalline breaking. Resinous between crystals Type II Small crystals are less Chalky Dull, earthy, or chalky than 0.05 mm and are earthy with pore space barely visible. Type III Space indicated Granular or Sandy or sugary between crystals or Sucrosic (sucrose) grains. Oolites are in granular class. Matrix Grain Size Symbol Large (coarse) >0.5 mm 1 Medium 0.25 to 0.5 mm m Fine 0.125 to 0.25 mm f Very fine 0.0625 to 0.125 mm vf Extremely fine < 0.0625 mm xf Pore-Size Classification Pore-Size Classification Visible to Visible Diameter Class Naked Eye 10x Magnification (ml) A No No <0.01 B No Yes 0.01 to 0.1 C Yes Yes 0.1 to 1.0 D Yes Yes >1.0 SPEJ P. 149

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Study on discriminant method of rock type for porous carbonate reservoirs based on Bayesian theory

Scientific Reports ◽

10.1038/s41598-021-98154-x ◽

2021 ◽

Vol 11 (1) ◽

Author(s):

Xinxin Fang ◽

Hong Feng

Keyword(s):

Middle East ◽

Rock Type ◽

Carbonate Reservoir ◽

Oil Field ◽

Carbonate Reservoirs ◽

Pressure Curve ◽

Permeability Model ◽

Permeability Characteristics ◽

Rock Types ◽

Study Results

AbstractRock typing is an extremely critical step in the estimation of carbonate reservoir quality and reserves in the Middle East. In order to recognize the rock types of carbonate reservoirs in the Mishrif Formation better, classify the reservoirs accurately, and establish the permeability model in line with the study area precisely, it is necessary to study the recognition method conforming to the actual situation of the study area. The practice shows that the current recognition methods based on capillary pressure curve, flow unit and NMR logging data can effectively distinguish rock types, but a large number of accurate experimental data are required, which can only be applied in a few cored well, however, cannot be applied in the whole oil field. In this study, based on core, thin section, logging data, the sedimentary characteristics of carbonate reservoir, logging response of four rock types as well as porosity and permeability characteristics of Mishrif Formation in W are comprehensively studied. Based on Bayesian stepwise discriminant theory in multivariate statistics, the Bayesian discrimination model based on conventional logging data is established. The examining results showed that, compared with the description of logging and coring, the accuracy of Bayesian discriminant model and cross confirmation rate have achieved more than 80% for the original sample. Reliability verification showed that the matching degree of the rock type recognized in the non-cored well with the core and mud logging was as high as 90%, which matched the depositional environment of the entire region. The study results confirm the validity and generalizability of the Bayesian method to identify and predict rock types, which can be applied to the entire Middle East region to solve the problem of the lack of core data to accurately evaluate the quality of non-cored wells and accurately predict production, meeting the needs of actual reservoir evaluation and production development in the Middle East.

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A new workflow to improve the carbonate reservoir types discrimination combing the empirical model decomposition and energy entropy classification methods

Interpretation ◽

10.1190/int-2017-0080.1 ◽

2018 ◽

Vol 6 (3) ◽

pp. T555-T567

Author(s):

Zhuoying Fan ◽

Jiagen Hou ◽

Chengyan Lin ◽

Xinmin Ge

Keyword(s):

Rock Type ◽

Well Logging ◽

Carbonate Reservoir ◽

Carbonate Reservoirs ◽

Reservoir Rock ◽

Well Logs ◽

Well Log ◽

Tahe Oilfield ◽

Rock Types ◽

Reservoir Type

Classification and well-logging evaluation of carbonate reservoir rock is very difficult. On one side, there are many reservoir pore spaces developed in carbonate reservoirs, including large karst caves, dissolved pores, fractures, intergranular dissolved pores, intragranular dissolved pores, and micropores. On the other side, conventional well-logging response characteristics of the various pore systems can be similar, making it difficult to identify the type of pore systems. We have developed a new reservoir rock-type characterization workflow. First, outcrop observations, cores, well logs, and multiscale data were used to clarify the carbonate reservoir types in the Ordovician carbonates of the Tahe Oilfield. Three reservoir rock types were divided based on outcrop, core observation, and thin section analysis. Microscopic and macroscopic characteristics of various rock types and their corresponding well-log responses were evaluated. Second, conventional well-log data were decomposed into multiple band sets of intrinsic mode functions using empirical mode decomposition method. The energy entropy of each log curve was then investigated. Based on the decomposition results, the characteristics of each reservoir type were summarized. Finally, by using the Fisher discriminant, the rock types of the carbonate reservoirs could be identified reliably. Comparing with conventional rock type identification methods based on conventional well-log responses only, the new workflow proposed in this paper can effectively cluster data within each rock types and increase the accuracy of reservoir type-based hydrocarbon production prediction. The workflow was applied to 213 reservoir intervals from 146 wells in the Tahe Oilfield. The results can improve the accuracy of oil-production interval prediction using well logs over conventional methods.

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An Aquifer Model for Fissured Reservoirs

Society of Petroleum Engineers Journal ◽

10.2118/4434-pa ◽

1975 ◽

Vol 15 (05) ◽

pp. 385-398 ◽

Cited By ~ 31

Author(s):

P.J. Clossman

Keyword(s):

Pressure Distribution ◽

Performance Studies ◽

Rock Type ◽

Porous Matrix ◽

Carbonate Reservoirs ◽

Basic Rock ◽

Petrophysical Properties ◽

Reservoir Performance ◽

Rock Types ◽

The Matrix

Abstract A model has been developed for describing aquifer influx in a fissured reservoir. This model includes petrophysical properties of good and poor rock, as petrophysical properties of good and poor rock, as well as fissure parameters. For the applications considered thus far, it has been found that flow in the fissures dominates the aquifer performance and that rock properties and spacing between fissures are of lesser importance. For a given aquifer, the fissure permeability and fissure volume fraction appear to be important parameters, as are rock permeability and porosity in cases of a high permeability and porosity in cases of a high percentage of poor rock. percentage of poor rock Introduction The use of material balance has been well established in analysis of reservoir performance. For water drive reservoirs, it is usually desirable to have a functional description of aquifer behavior. Such a description is provided by the functions obtained by van Everdingen and Hurst for homogeneous and isotropic reservoirs. This method uses one set of values of permeability, porosity, and compressibility, and usually requires some history matching or curve fitting for determining the best values. Functions analogous to those of van Everdingen and Hurst also would be useful in reservoir performance studies of fissured reservoirs. Any performance studies of fissured reservoirs. Any attempt to formulate a realistic model for such systems, however, will usually confront the problem of insufficient knowledge of aquifer properties. There usually will be a comparatively large number of degrees of freedom corresponding to parameters introduced into the theory. Nevertheless, such a model should provide insight into the relative importance of certain variables. It may also serve as a framework in which more accurate information, if eventually obtained, could be used. Pressure behavior was used to study fissured reservoir properties by Pollard, who characterized the pressure buildup by three exponentials. These exponentials corresponded to a skin near the well, transient behavior in the fracture system, and transient flow of fluid from matrix to fissures. A characteristics feature of fissured reservoir systems and the reservoir fast fluid pressure response of the fissure system compared with response in the porous matrix. A model that treats this aspect porous matrix. A model that treats this aspect appropriately as proposed by Warren and Root, who assumed that flow of fluid from matrix to fissures could be treated as quasi-steady state. The problem of transient pressure distribution within an actual block of the reservoir was thereby circumvented. This model was further studied by Odeh. Kazemi replaced the network of fractures with an equivalent set of horizontal fractures and solved numerically for pressure distribution in fissures and matrix. Because the dimensionless time scale based on fracture properties and well radius was long, Warren and Root and Odeh were able to use the long-time solution for the constant terminal rate case of pressure behavior in an oil reservoir. In the present instance, the inner aquifer radius may be quite large, so that we must consider smaller dimensionless times, and will require a general solution. The actual times of interest, however, will not be so small as to invalidate the model. This model is being considered for use in fissured carbonate reservoirs where two basic rock types, defined in terms of porosity, are sometimes specified. In such cases, the rock permeabilities usually are very much smaller than the fissure permeability, The matrix can be considered as permeability, The matrix can be considered as being made up of good and poor rock. Wide variations in rock type are often encountered in carbonate reservoirs. The designations of good and "poor" are largely arbitrary. A typical example would be: good porosity greater than 12 percent, and poor-porosity 2 to 12 percent, with the remainder poor-porosity 2 to 12 percent, with the remainder of the rock nonproductive. In some cases, however, it may be sufficient to specify only one rock type. In studying the constant terminal pressure case it is desirable to reformulate the fissured reservoir model to include the additional features of change, boundary conditions and two basic rock types. SPEJ P. 385

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