Porosity In Carbonate Reservoirs Research Articles

An advanced ensemble modeling approach for predicting carbonate reservoir porosity from seismic attributes

This study uses a machine learning (ML) ensemble modeling approach to predict porosity from multiple seismic attributes in one of the most promising Main Dolomite hydrocarbon reservoirs in NW Poland. The presented workflow tests five different model types of varying complexity: K-nearest neighbors (KNN), random forests (RF), extreme gradient boosting (XGB), support vector machine (SVM), single layer neural network with multilayer perceptron (MLP). The selected models are additionally run with different configurations originating from the pre-processing stage, including Yeo–Johnson transformation (YJ) and principal component analysis (PCA). The race ANOVA method across resample data is used to tune the best hyperparameters for each model. The model candidates and the role of different pre-processors are evaluated based on standard ML metrics – coefficient of determination (R2), root mean squared error (RMSE), and mean absolute error (MAE). The model stacking is performed on five model candidates: two KNN, two XGB, and one SVM PCA with a marginal role. The results of the ensemble model showed superior accuracy over single learners, with all metrics (R2 0.890, RMSE 0.0252, MAE 0.168). It also turned out to be almost three times better than the neural net (NN) results obtained from commercial software on the same testing set (R2 0.318, RMSE 0.0628, MAE 0.0487). The spatial distribution of porosity from the ensemble model indicated areas of good reservoir properties that overlap with hydrocarbon production fields. This observation completes the evaluation of the ensemble technique results from model metrics. Overall, the proposed solution is a promising tool for better porosity prediction and understanding of heterogeneous carbonate reservoirs from multiple seismic attributes.

Integration of Multiple Bayesian Optimized Machine Learning Techniques and Conventional Well Logs for Accurate Prediction of Porosity in Carbonate Reservoirs

The accurate estimation of reservoir porosity plays a vital role in estimating the amount of hydrocarbon reserves and evaluating the economic potential of a reservoir. It also aids decision making during the exploration and development phases of oil and gas fields. This study evaluates the integration of artificial intelligence techniques, conventional well logs, and core analysis for the accurate prediction of porosity in carbonate reservoirs. In general, carbonate reservoirs are characterized by their complex pore systems, with the wide spatial variation and highly nonlinear nature of their petrophysical properties. Therefore, they require detailed well-log interpretations to accurately estimate their properties, making them good candidates for the application of machine learning techniques. Accordingly, a large database of (2100) well-log records and core-porosity measurements were integrated with four state-of-the-art machine learning techniques (multilayer perceptron artificial neural network, MLP-ANN; Gaussian process regression, GPR; least squares gradient boosting ensemble, LS-Boost; and radial basis function neural network, RBF-NN) for the prediction of reservoir porosity. The well-log data used in this study include sonic acoustic travel time, Gamma-ray, and bulk density log records, which were carefully collected from five wells in a carbonate reservoir. This study revealed that all the artificial intelligence models achieved high accuracy, with R-squared values exceeding 90% during both the training and blind-testing phases. Among the AI models examined, the GPR model outperformed the others in terms of the R-squared values, root-mean-square error (RMSE), and coefficient of variation of the root-mean-square error (CVRMSE). Furthermore, this study introduces an artificially intelligent AI-based correlation for the estimation of reservoir porosity from well-log data; this correlation was developed using an in-house, Fortran-coded MLP-ANN model presented herein. This AI-based correlation gave a promising level of accuracy, with R-squared values of 92% and 90% for the training and blind-testing datasets, respectively. This correlation can serve as an accurate and easy-to-use tool for porosity prediction without any prior experience in utilizing or implementing machine learning models.

A comparison of machine learning methods to predict porosity in carbonate reservoirs from seismic-derived elastic properties

Porosity prediction from seismic data in carbonate reservoirs is challenging because the common presence of heterogeneities in carbonates makes it difficult to establish a clear physical relationship between reservoir properties and elastic responses. Regarding the strong nonlinearities underlying the relationship, machine learning is considered to be a good alternative to traditional methods. We compare several representative supervised machine learning algorithms (light gradient boosting machine [LightGBM], extreme gradient boosting, categorical boosting, random forest, multilayer perceptron, and convolutional neural network) in terms of predictive accuracy and runtime for crosswell blind tests and seismic prediction in a heterogeneous carbonate reservoir, offshore Brazil. The machine learning models are trained with the porosity and elastic parameters (P-impedance and [Formula: see text] ratio) from the smoothed and standardized logging data. Then, we apply the trained model on the inverted elastic properties to predict the porosity profile from seismic data. In the crosswell blind tests for the studied reservoir, LightGBM clearly stands out from the compared machine learning methods with the highest predictive accuracy and the shortest runtime, showing potential for fast and reliable porosity prediction from seismic data. In addition, we analyze the geologic factors (clay content, oil saturation, and relative depth) that possibly affect the predictive accuracy. We find that, with the constraints from clay content and fluids saturation, the performance of porosity prediction from elastic parameters can be further improved to a certain degree.

Fluid evolution and petroleum accumulation in the precambrian gas reservoirs of the Sichuan Basin, SW China

Deep marine carbonates comprise one of the most significant reservoir types globally. Reconstruction of Precambrian oil reservoirs and the complex tectonism that affected Precambrian carbonate reservoirs demonstrate the complexity of the natural gas enrichment mechanism. A comparison between the fluid evolution of the well-preserved reservoirs in the central Sichuan Basin and the poorly preserved reservoirs in the southeastern Sichuan Basin offers insights into the factors that control the preservation of ancient reservoirs. We conducted geochemical analysis of the multistage cementation sequence, Raman quantitative analysis on fluid (gas) inclusions, and rare earth element (REE) analysis of diagenetic fluid environments. Hydrocarbon migration can cause variations in the diagenetic environment. Quantitative Raman measurements of the trapping pressure, trapping temperature, and composition of fluid (gas) inclusions are also useful in defining periods of gas accumulation. In situ U–Pb dating results of dolomite veins indicate that extensive dolomitization in the Sichuan Basin began during the early Cambrian. In the central Sichuan Basin, reservoir pressure evolved from normal during the Middle Jurassic to strongly overpressured during the mid-Cretaceous. Overpressure generated before Himalayan tectonism appears to be positively correlated with gas preservation. Overpressure within inclusions bearing hydrogen sulfide indicates that thermochemical sulfate reduction (TSR) does not produce intense dissolution that increases the porosity of carbonate reservoirs and reduces pore pressure. Poorly preserved reservoirs were intruded by exogenous and hydrothermal fluids but remained normally pressured. Secondary methane-rich gas inclusions record normal pressure conditions during the early Paleogene.

A unified analysis of fully mixed virtual element method for wormhole propagation arising in the petroleum engineering

Wormhole propagation, arising in petroleum engineering, is used to describe the distribution of acid and the increase of porosity in carbonate reservoir under the dissolution of injected acid and plays a very important role in the product enhancement of oil and gas reservoirs. In this paper, a fully mixed virtual element method (VEM) is employed to discretize this problem, in which mixed VEM is used not only for the Darcy flow equations but also for approximation the concentration equation by introducing an auxiliary flux variable to guarantee full mass conservation. The stability, existence and uniqueness of solution of the associated mixed VEM are proved by fixed point theory. Also, we obtain unconditionally optimal error estimate for concentration and auxiliary flux variable of convection-diffusion equation, as well as for the velocity and pressure of Darcy equations in the L 2 norm. Finally, several numerical experiments are presented to support the theoretical analysis of convergence and to illustrate the applicability for solving actual problems.

Factors influencing stylolite formation in the Cambrian Longwangmiao Formation, Sichuan Basin, SW China

In the deep and ultra-deep carbonate reservoirs, the porosity will be reduced due to the compaction, pressure solution, and cementation which are considered as the crucial factors for the mechanism of high-quality carbonate reservoirs. However, it is still a challenge to quantify the influence of stylolites on the Longwangmiao Formation carbonate reservoirs. To better understand the controls on the formation and distribution of stylolites, the Longwangmiao Formation is selected as an example to evaluate the effect of stylolites on the carbonate reservoirs. The mineralogy of the Longwangmiao Formation reservoirs is mainly dominated by dolomite (79.6%) with minor calcite (11.4%), and terrigenous minerals (clay and quartz) (5.6%). The rocks with dolomite content of more than 80%, calcite content of less than 30%, and terrigenous minerals of less than 1% have lower stylolite density and amplitude. The content of dolomite can affect the occurrence of stylolite indicating that the higher abundance of dolomite has a lower density and amplitude of stylolite. Based on the multiple techniques, four types of carbonate lithofacies were recognized, including the grainstone (dolo-grainstone, grainstone), packstone (dolo-packstone, packstone), wackestone (dolo-wackestone, wackestone), and mudstone (dolo-mudstone, mudstone). The distribution of stylolite also shows the lithofacies-specific behavior in the Longwangmiao Formation carbonate reservoirs. The lithofacies of grainstone shows the lowest density and amplitude of stylolite, while the occurrence of stylolite in the mudstone shows the highest abundance. Vertically, the stylolite density and amplitude in the lower part of the fourth-order sequences is higher than this in the upper part. This study suggested that the dolomitized lithofacies with relatively high grain (50–70%) and cement (∼25%) contents can resist the pressure solution and can preserve the porosity of carbonate reservoirs.

In situ diamond anvil cell (DAC) experiments on equilibrated carbonate–CO2–H2O interaction under elevated temperature and pressure

The carbonate–CO2–H2O interaction in a closed system under burial conditions was simulated in diamond anvil cell (DAC) with an in situ Raman spectroscopy. Experiments were performed in \({\text{H}}_{2} {\text{CO}}_{3}\) solution at acidic pH (≈ 5.6), 20–260 °C, and atmospheric pressure to about 400 MPa. Pressure was first solely increased to separately evaluate the pressure effect on carbonate dissolution/precipitation. Then temperature and pressure were increased together alike in the burial process, to monitor the dissolution/precipitation tendency of carbonate during burial. A continuous dissolution was observed for both limestone and dolostone when solely increasing pressure. A rapid dissolution and then continuous precipitation were observed when increasing temperatures and pressures simultaneously. These observations indicate that pressure has a positive effect (prograde solubility), while temperature has a negative effect (retrograde solubility) on CO2 solubility and carbonate dissolution. In case of low initial CO2 content as our experiments revealed, the increase in solid carbonate volume and a counterbalance decrease in porosity caused merely by increasing burial depth are minor (< 0.23%). The porosity decrease of dolostone was likely less than that of limestone at smaller burial depth (< 1.5 km), and notable at bigger burial depth. This work may help to improve our understanding on carbonate reservoir porosity evolution during burial.

High-order bound-preserving discontinuous Galerkin methods for wormhole propagation on triangular meshes

Wormhole propagation, arising in petroleum engineering, is used to describe the distribution of acid and the increase of porosity in carbonate reservoir under dissolution of injected acid. The important physical features of porosity and acid concentration include their boundedness between 0 and 1, as well as the monotone increasing for porosity. How to keep these properties in the simulation is crucial to the robustness of the numerical algorithm. In this paper, we propose high-order bound-preserving discontinuous Galerkin methods to keep these important physical properties. The main technique is to introduce a new variable r to replace the original acid concentration and use a consistent flux pair to deduce a ghost equation such that the positive-preserving technique can be applied on both original and deduced equations. A high-order slope limiter is used to keep a polynomial upper bound which changes over time for r. Moreover, the high-order accuracy is attained by the flux limiter. Numerical examples are given to demonstrate the high-order accuracy and bound-preserving property of the numerical technique.

Porosity Prediction Using Neural Network Based on Seismic Inversion and Seismic Attributes

It has done a study of porosity prediction by using neural network. The study uses 2D seismic data post-stack time migration (PSTM) and 2 well data at field “T”. The objective is determining distribution of porosity. Porosity in carbonate reservoir is actually heterogeneous, complex and random. To face the complexity the neural network method has been implemented. The neural network algorithm uses probabilistic neural network based on best seismic attributes. It has been selected by using multi-attribute method with has high correlation. The best attributes which have been selected are amplitude envelope, average frequency, amplitude weighted phase, integrated absolute amplitude, acoustic impedance, and dominant frequency. The attribute is used as input to probabilistic neural network method process. The result porosity prediction based on probabilistic neural network use non-linear equation obtained high correlation coefficient 0.86 and approach actual log. The result has a better correlation than using multi-attribute method with correlation 0.58. The value of distribution porosity is 0.05–0.3 and it indicates the heterogeneous porosity distribution generally from the bottom to up are decreasing value.

Development and calibration of a reactive transport model for carbonate reservoir porosity and permeability changes based on CO2 core-flood experiments

Beneficial pore space and permeability enhancements are likely to occur as CO2-charged fluids partially dissolve carbonate minerals in carbonate reservoir formations used for geologic CO2 storage. The ability to forecast the extent and impact of changes in porosity and permeability will aid geologic CO2 storage operations and lower uncertainty in estimates of long-term storage capacity. Our work is directed toward developing calibrated reactive transport models that more accurately capture the chemical impacts of CO2-fluid-rock interactions and their effects on porosity and permeability by matching pressure, fluid chemistry, and dissolution features that developed as a result of reaction with CO2-acidified brines at representative reservoir conditions. We present new results from experiments conducted on seven core samples from the Arbuckle Dolostone (near Wellington, Kansas, USA, recovered as part of the South-Central Kansas CO2 Demonstration). Cores were obtained from both target reservoir and lower-permeability baffle zones, and together these samples span over 3–4 orders of magnitude of permeability according to downhole measurements. Core samples were nondestructively imaged by X-ray computed tomography and the resulting characterization data were mapped onto a continuum domain to further develop a reactive transport model for a range of mineral and physical heterogeneity. We combine these new results with those from previous experimental studies (Smith et al., 2013; Hao et al., 2013) to more fully constrain the governing equations used in reactive transport models to better estimate the transition of enhanced oil recovery operations to long-term geology CO2 storage. Calcite and dolomite kinetic rate constants (molm−2s−1) derived by fitting the results from core-flood experiments range from kcalcite,25C=10−6.8 to 10−4.6, and kdolomite,25C=10−7.5 to 10−5.3. The power law-based porosity-permeability relationship is sensitive to the overall pore space heterogeneity of each core. Stable dissolution fronts observed in the more homogeneous dolostones could be accurately simulated using an exponential value of n=3. Unstable dissolution fronts consisting of preferential flowpaths could be simulated using an exponential value of n=3 for heterogeneous dolostones, and larger values (n=6–8) for heterogeneous limestones.

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.

Detecting vuggy porosity in carbonate reservoirs by well logs

Vuggy porosity is a type of porosity in carbonate rocks. This kind of porosity significantly affects the permeability, pressure drop and recovery factor in the reservoir. Therefore, their identification and modeling is important for the reservoir characterization and history matching. Image logs, RCAL and SCAL tests are main tools to determine vugs, though all are costly and sometimes unavailable. Thus, development of a generalized approach to recognize vugs in reservoirs will be significant. In this paper, a combined majority voting-Parzen–wavelet based algorithm is developed using gamma ray (GR), neutron porosity (NPHI), bulk density (RHOB) and sonic (DT) logs for identification of vugs in frequency domain. The agreement between the core tests results and the results of this newly developed method confirms the application of proposed new method.

Определение пористости карбонатных коллекторов по данным нейтронного каротажа

The article presents a methodology for determining the porosity of carbonate reservoirs for evaluation of oil and gas reserves using a single dependence for neutron-gamma and neutron-neutron logs.

Climatic controls on facies in Palaeogene Mediterranean subtropical carbonate platforms

Cenozoic carbonate platforms in the central Mediterranean region show distinct vertical changes in carbonate skeletal assemblages and porosity characteristics that reflect shifts in environmental conditions affecting the western Tethys. The Photozoan Association produced by carbonate ecosystems adapted to low nutrient environments and the Heterozoan Association favoured by mesotrophic conditions alternate through time over the Malta Platform and nearby carbonate platforms, although not in phase with trans-Mediterranean Oligocene carbonates. This anomaly reflects the transitional nature of Cenozoic climate as well as continental convergence of the Tethyan margins. Restricted conditions amplified the effect of nutrient flux from North African fluvial systems, which was controlled by meridional shifts in the inter-tropical convergence zone (ITCZ) precipitation belt. We model the climate–carbonate interaction by comparing the global oxygen isotope proxy to ice volume and meridional position of the ITCZ to changes in trophic level of carbonate ecosystems. The results show that the development of Palaeogene Mediterranean photozoan assemblages coincides with periods when the ITCZ had shifted away from North Africa (as is the case presently), whereas the heterozoan assemblages thrived during increased nutrient flux when the precipitation belt was located over the Sahara. The climatic controls resulted in facies characteristics that exert a fundamental influence on porosity in carbonate reservoirs.

The relationship between petroleum emplacement and carbonate reservoir quality: examples from Abu Dhabi and the Amu Darya Basin

The relative importance of petroleum emplacement in inhibiting diagenetic processes and preserving porosity and permeability in Lower Cretaceous, Thamama Group (Kharaib Formation) carbonate reservoirs of Abu Dhabi, UAE, and in Callovian-Kimmeridgian carbonate reservoirs of the Amu Darya Basin in Uzbekistan and Turkmenistan, has been evaluated by combining geologic, petrophysical and geochemical data. When petroleum emplacement is synchronous with and prior to significant burial cementation in carbonates, primary petroleum inclusions are trapped in the cements. The process appears to be characterised by steep intra-field porosity-depth trends within a more gradual regional decline in porosity with depth. This has profound implications for the prediction of porosity in carbonate reservoirs. Reservoir quality is better in grainstones and packstones compared to adjacent wackestones and lime mudstones in the Kharaib Formation because of preserved macroporosity (intergranular, vuggy, mouldic); the pore system in the finer units is dominated by micropores. These features indicate a primary textural control on porosity and permeability. Within the grainstones and packstones, macroporosity is variably filled by late equant sparry calcite cements. Porosity and permeability variations in grainstones and packstones at a reservoir scale are therefore controlled by the variation in amount of equant sparry calcite cement. This in turn depends on the timing of the precipitation of this cement relative to petroleum emplacement, as shown by fluid inclusion data. Where petroleum emplacement has occurred relatively early, at migration foci, prior to significant burial cementation by equant sparry calcite, reservoir quality is preserved. Where it has occurred after significant burial cementation, reservoir quality has been destroyed. In the Amu Darya sequences, primary macroporosity is commonly preserved down to depths of 11,000 ft (3.5 km) with differences in the porosity and permeability characteristics of grainstones being controlled by variations in the amount of early, probably freshwater, cement and the extent of associated dissolution. Small volumes of burial cements do occur, but they do not contain petroleum inclusions. Consequently, there is no firm evidence that petroleum emplacement has inhibited diagenesis in this area. This part of the study has shown that it is not always possible to obtain conclusive evidence from the diagenesis to pin down the processes responsible for the preservation of reservoir quality and that petroleum filling may not always be the primary cause. The relationships documented here show that the ‘race for space’ between diagenetic waters and petroleum is a major control on reservoir quality in the Thamama Group carbonate reservoirs, but is not so important for the Jurassic carbonates in the Amu Darya basin.

Abstract: A New Approach to Evaluate and Characterize Secondary Porosity in Carbonate Reservoirs of South Mexico.&amp;nbsp;

Abstract: A New Approach to Evaluate and Characterize Secondary Porosity in Carbonate Reservoirs of South Mexico.&amp;nbsp;

Genesis and development of porosity in carbonate reservoirs—Fluid inclusion evidence

Fluid inclusions in minerals filled in pores of reservoir rocks can be used as a good indicator of pore genesis and development so as to shed light on oil generation, migration and accumulation. The relationship between pore evolution and oil generation has been established based on fluid inclusion studies on the Lower Ordovician carbonate reservoir strata in the Ordos Basin, Northwest China. Seven stages of porosity development can be recognized, i. e., the penecontemporaneous, the early and middle-late diagenetic, the supergene, the early, middle and late re-burying stages. The dissolution pores and fissures formed in the supergene and middle-late re-burying stages and the structural fractures formed in the late re-burying stage constitute the major traps of oil and gas. The major phase of oil migration and accumulation took place between Late Jurassic and Cretaceous, corresponding to the middle and late re-burying stages. The generation and accumulation of oil can be closely related to Yenshanian tectonics.

Enhancement of Petroleum Systems by Raft Tectonics: A Type Example from Offshore Northern Angola

Raft tectonics (tectonique en radeaux) is the most extreme form of thin-skinned extension. Gravity-induced stretching of the cover causes the overburden above a decollement of Aptian salt to separate into allochthonous fault blocks or [open quotes]rafts.[close quotes] Widening, deepening depocenters between rafts are filled with younger, mainly Tertiary sediments. Such a high degree of extension creates a special tectonic style, which is particularly visible on the continental shelf of northern Angola. More relevant, though, is the economic importance of raft tectonics, which substantially enhance the petroleum systems of the area. Where the cover is typically thin, the generative petroleum subsystem is [open quotes]subsalt,[close quotes] as source rocks are only mature in lacustrine environments of the rift basins or the cratonic lowstand wedge of earlier ages. If vertical migration of hydrocarbons is prevented by a seal of undeformed, laterally continuous salt, found in [open quotes]prerafts[close quotes] of moderately stretched overburden, low-impedance conditions prevail and most hydrocarbons migrate laterally and disperse updip, forming the well known outcropping asphalts. The migration-entrapment petroleum subsystem may work, however, under favorable conditions made possible by raft tectonics in several ways and illustrated in the paper using post-stack migrated seismic sections and case histories of specific fieldsmore » of the area (Lombo East, Sulele). (1) Vertical migration is made easier by salt seals breached during extensional salt welding. (2) Albian carbonate reservoir porosity of the Pinda formation is enhanced by shoaling over tilted fault blocks. (3) Extensional structural traps impede lateral migration of hydrocarbons from the Pinda. Therefore, an accurate picking of the evaporitic interval, combined with a thorough discrimination of the structural targets, are essential to the success of exploration.« less

Stylolite Porosity in Carbonate Reservoirs: ABSTRACT

Stylolite Porosity in Carbonate Reservoirs: ABSTRACT

Modelling Carbonate Reservoir Porosity For Enhanced Recovery Schemes

Abstract Most carbonate rock porosity classifications are generic and do not account for features of the pore systems that may affect fluid movement and withdrawal-important factors in the production of hydrocarbons from these rocks. Mercury injection capillary pressure (MICP) analyses of carbonate reservoirs supply valuable information on the interaction between non-wetting fluids and reservoir porosity. Some 200 analyses of a variety of Mississippian carbonate reservoirs in southern Saskatchewan indicate that porosity can be simplified into three types; inter-crystal, cavity and mixed (inter-crystal and cavity). The categories can be recognized by the degree of uniformity of pore throat sizes in the reservoir rock; a high degree of uniformity indicates inter-crystal porosity and a wide variation in pore throat size is representative of cavity porosity. Entry pressure is a second MICP factor that tells something about the reservoir rock. High entry pressures are commonly related to calcitic reservoir rocks with inter-crystal porosity: intermediate entry pressure indicates dolomite with inter-crystal porosity; and low pressures are representative of calcitic or dolomitic rocks with abundant large cavities (mesopores). Pore system/fluid interaction can be shown to influence efficient withdrawal of hydrocarbons from a reservoir, thus productivity may vary markedly due to differences in porosity types over the lateral extent of a producing zone. Introduction During the past ten years, several graduate students in the Department of Geology, University of Regina, and the author have investigated several geological aspects of the Mississippian reservoir rocks in southeastern Saskatchewan. These include studies into the microfacies, diagenesis and nature of the pore systems in the Benson (Midale Beds)(1), Glen Ewen (Midale Beds)(2), Innes (Frobisher Beds)(3,4) and Hummingbird (Ratcliff Beds)(5) oilfields. In addition to these completed investigations, a study is at present being carried out on three Ratcliffe Beds producing areas: Flat Lake, Lake Alma, and Oungre. Most of these studies have been generously supported by the Saskatchewan Department of Energy and Mines, in an effort to establish a readily available source of information on carbonate rock reservoirs for enhanced recovery schemes. The Hummingbird study was financed through a grant to Dr. L. W. Vigrass from Hudson's Bay Oil and Gas Co. Ltd. The pore systems of the reservoirs in these fields have been studied using mercury injection capillary pressure analyses, to establish pore throat size distribution and a variety of fluid response characteristics, including entry pressure, ejection efficiency and unsaturated pore volume. The results of these analyses were enhanced by detailed examination of the reservoir rocks using scanning electron and light microscopy. The variety of carbonate rock types constituting the reservoirs in the Mississippian fields studied have made it possible for the writer to establish a simplified classification of porosity for carbonate reservoir rocks. Because Mississippian rocks are used as the basis for this classification a brief review of their important characteristics is presented below. Geologic Setting Mississippian rocks in southern Saskatchewan were deposited on the northern flank of the Williston Basin in a marine seaway in which paleobathymetry exerted an influence on the distribution of facies.