Detection and Estimation of Dead-End Pore Volume in Reservoir ROCK by Conventional Laboratory Tests

1966 ◽  
Vol 6 (03) ◽  
pp. 206-212 ◽  
Author(s):  
I. Fatt ◽  
M. Maleki ◽  
R.N. Upadhyay
Keyword(s):  
Laboratory Tests ◽  
Saline Solution ◽  
Pore Space ◽  
Flow Behavior ◽  
Reservoir Rock ◽  
Formation Factor ◽  
Pressure Transient ◽  
Reservoir Rocks ◽  
Reservoir Flow ◽  
Dead End

Abstract Conventional laboratory core analysis tests on samples of two limestone reservoir rocks indicate that about 20 per cent of PV is in dead-end pores. These tests (electric logging formation factor. mercury injection capillary pressure and miscible displacement) were carried out on 3/4-in. diameter test plugs. Test results show a clear difference between these samples and sandstone or homogeneous limestone reservoir rock. Although the amount of dead-end pore space can be only roughly estimated, the presence of such pore space seems clearly indicated. Pressure transient studies also show presence of dead-end PV. Although they do not give quantitative results, pressure transient data yield a reasonable estimate of the size of the neck connecting dead-end pores to the main flow channels. Introduction Equations conventionally used to describe reservoir flow behavior contain the implicit assumption that all connected pore spaces contributed to both porosity and permeability. Several authors have pointed out the changes in pressure transient behavior and in electric log interpretation that may result if this assumption is incorrect and, instead, dead-end or cul-de-sac pores are present. There is a need for laboratory tests that can detect presence of dead-end pores in core samples. With such information on hand the petroleum engineer can make more rational use of the mathematical tools now available for analysis of reservoir flow behavior. This paper describes laboratory studies designed to detect and, if possible, give a quantitative measure of dead-end PV in laboratory-size core plugs. Three reservoir rocks were used, two of which were limestones suspected of having dead- end pore spaces and a well-known sandstone, used as a comparison standard, in which there is believed to be little or no dead-end pore space. All the studies were designed to measure the natural dead-end PV; i.e., the pore space which is dead-ended because of rock structure. During multiphase flow in a rock without dead-end pores, some parts of one of the phases can become surrounded by the other, thereby giving (for certain flow behavior) an effective dead-end PV 8,9. Such behavior will not be described here. FORMATION FACTOR THEORY One of the simplest laboratory measurements which can be made on core plugs is the electric logging formation factor F. By definition: (1) where Ro is the resistivity of the core plug saturated with a saline solution of resistivity Rw. Difficulties in using this definition of F may arise when the solid framework of the rock is electrically conducting. These difficulties may be largely circumvented by using a highly conducting saline solution so that the conduction contribution of the solid is negligible. There are no useful theoretical relationships between F and the porosity phi. A widely used empirical relation is the one given by Archie: (2) where m, called the cementation factor, is expected to be a constant for a given type of rock. Pirson shows that for reservoir rocks, m varies from about 1.3 for loosely cemented sandstones to 2.2 for highly cemented sandstones or carbonate rocks. SPEJ P. 206ˆ

A faster method for erosion and dilation of reservoir pore-complex images

1988 ◽  
Vol 25 (7) ◽  
pp. 1128-1131 ◽  
Author(s):  
J. R. Parker
Keyword(s):  
Flow Behavior ◽  
Reservoir Rock ◽  
Two Dimensional ◽  
Thin Sections ◽  
Reservoir Rocks ◽  
Image Processing Techniques ◽  
The Third ◽  
Computer Image Processing ◽  
Third Dimension ◽  
Processing Techniques

Studies of thin sections of reservoir rock have been conducted for some time with the goal of understanding flow behavior and estimating physical properties. These sections are essentially two dimensional, but it has always been assumed that the results obtained can be extrapolated to the third dimension. Computer image-processing techniques are often used in this sort of analysis because of the large amounts of data contained in a single digitized section image. One of the methods used to process these images is erosion–dilation, wherein layers of each pore are stripped off (erosion) and then replaced (dilation). This results in a smoothing of the pore perimeters and can be used to estimate pore radii, volume, and roughness. Because of the size of each image, erosion–dilation of images of the pore complex of reservoir rocks is a time-consuming process. A new method called global erosion is much faster, with no increase in memory requirement or decrease in accuracy. This should permit the processing of larger images or a greater number of small images than does the standard method.

Characterization of a Carbonate Reservoir With Pressure-Transient Tests and Production Logs: Tengiz Field, Kazakhstan

2001 ◽  
Vol 4 (04) ◽  
pp. 250-259
Author(s):  
K.T. Chambers ◽  
W.S. Hallager ◽  
C.S. Kabir ◽  
R.A. Garber
Keyword(s):  
Flow Behavior ◽  
Carbonate Reservoir ◽  
Dual Porosity ◽  
Rate Data ◽  
Pressure Data ◽  
Pressure Transient ◽  
Reservoir Flow ◽  
Black Oil ◽  
Fluid Properties ◽  
Tengiz Field

Summary The combination of pressure-transient and production-log (PL) analyses has proved valuable in characterizing reservoir flow behavior in the giant Tengiz field. Among the important findings is the absence of clear dual-porosity flow. This observation contradicts an earlier interpretation that the reservoir contains a well-connected, natural fracture network. Fracturing and other secondary porosity mechanisms play a role in enhancing matrix permeability, but their impact is insufficient to cause dual-porosity flow behavior to develop. Flow profiles measured with production logs consistently show several thin (10 to 30 ft) zones dominating well deliverability over the thick (up to 1,040 ft) perforation intervals at Tengiz. A comparison of PL results and core descriptions reveals a good correlation between high deliverability zones and probable exposure surfaces in the carbonate reservoir. Contrary to earlier postulations, results obtained from pressure-transient and PL data at Tengiz do not support rate-sensitive productivity indices (PI's). Inclusion of rate variations in reconciling buildup and drawdown test results addressed this issue. We developed wellbore hydraulic models and calibrated them with PL data for extending PI results to wells that do not have measured values. A simplified equation-of-state (EOS) fluid description was an important component of the models because the available black-oil fluid correlations do not provide reliable results for the 47°API volatile Tengiz oil. Clear trends in reservoir quality emerge from the PI results. Introduction A plethora of publications exists on transient testing. However, only a few papers address the issue of combining multidisciplinary data to understand reservoir flow behavior (Refs. 1 through 4 are worthy of note). We used a synergistic approach by combining geology, petrophysics, transient tests, PL's, and wellbore-flow modeling to characterize the reservoir flow behavior in the Tengiz field. Understanding this flow behavior is crucial to formulating guidelines for reservoir management. Permeability estimation from pressure-transient data is sensitive to the effective reservoir thickness contributing to flow. Unfortunately, difficulties associated with the calibration of old openhole logs, sparse core coverage, and a major diagenetic overprint of solid bitumen combine to limit the identification of an effective reservoir at Tengiz based on openhole log data alone. Consequently, PL's have been used to identify an effective reservoir in terms of its flow potential. A limitation of production logs is that they only measure fluid entering the wellbore and are not necessarily indicative of flow in the reservoir away from the well. Pressure data from buildup and drawdown tests, on the other hand, provide insights into flow behavior both near the well and farther into the reservoir. The combination of pressure-transient analysis using simultaneous downhole pressure and flow-rate data along with measured production profiles provides an opportunity to reconcile near-wellbore and in-situ flow behavior. Expansion of reservoir fluids along with formation compaction provides the current drive mechanism at Tengiz because the reservoir is undersaturated by over 8,000 psia. As the field is produced, reservoir stresses will increase in response to pressure decreases.5 Increased stresses can significantly reduce permeability if natural fractures provide the primary flow capacity in the reservoir. Wells producing at high drawdowns provide an opportunity to investigate the pressure sensitivity of fractures within the near-wellbore region. Early interpretations of pressure-transient tests at Tengiz uncovered a significant discrepancy between buildup and drawdown permeability, despite efforts to carefully control flow rates during the tests. Drawdown permeabilities typically exceeded the buildup results by 20 to 50%. Although this finding appears counterintuitive to the expectation that drawdowns (that is, higher stresses) would lead to lower permeability, it indicated a possible stress dependence on well deliverability. The method proposed by Kabir6 to reconcile differences between drawdown and buildup results proved useful in addressing this issue. The opportunities to collect PL and downhole pressure data at Tengiz are limited by mechanical conditions in some wells and by the requirement to meet the processing capacity of the oil and gas plant. On the other hand, accurate wellhead-pressure and flow-rate data are routinely available. Wellbore hydraulic calculations provide a basis for calculating flowing bottomhole pressures (FBHP's) with the available surface data. Calculated FBHP's can be combined with available reservoir pressure data to determine PI's for wells lacking bottomhole measurements. The ability to compute accurate fluid properties is critical in applying this approach. Unfortunately, the black-oil correlations routinely used in wellbore hydraulic calculations7–9 do not provide reliable results for the volatile Tengiz oil. We obtained good agreement between laboratory measurements of fluid properties and calculated values using a simplified EOS.10 Surface and bottomhole data collected during PL operations provide a basis for validating wellbore hydraulic calculations. Networks of natural fractures can dominate the producing behavior of carbonate reservoirs such as Tengiz. Early identification of fractured reservoir behavior is critical to the successful development of these types of reservoirs.11 We present an approach for resolving reservoir flow behavior by combining production profiles, pressure-transient tests, and wellbore hydraulic calculations. Furthermore, we discuss the PL procedures developed to allow acquisition of the data required for all three types of analyses in a single logging run. Field examples from Tengiz highlight the usefulness of this approach.

Machine-Learning-Assisted Segmentation of Focused Ion Beam-Scanning Electron Microscopy Images with Artifacts for Improved Void-Space Characterization of Tight Reservoir Rocks

SPE Journal ◽  
2021 ◽  
pp. 1-20
Author(s):  
Andrey Kazak ◽  
Kirill Simonov ◽  
Victor Kulikov
Keyword(s):  
Image Segmentation ◽  
Focused Ion Beam ◽  
Pore Space ◽  
Ion Beam ◽  
Reservoir Rock ◽  
Data Sets ◽  
Sem Images ◽  
Reservoir Rocks ◽  
Tight Reservoir

Summary The modern focused ion beam-scanning electron microscopy (FIB-SEM) allows imaging of nanoporous tight reservoir-rock samples in 3D at a resolution up to 3 nm/voxel. Correct porosity determination from FIB-SEM images requires fast and robust segmentation. However, the quality and efficient segmentation of FIB-SEM images is still a complicated and challenging task. Typically, a trained operator spends days or weeks in subjective and semimanual labeling of a single FIB-SEM data set. The presence of FIB-SEM artifacts, such as porebacks, requires developing a new methodology for efficient image segmentation. We have developed a method for simplification of multimodal segmentation of FIB-SEM data sets using machine-learning (ML)-based techniques. We study a collection of rock samples formed according to the petrophysical interpretation of well logs from a complex tight gas reservoir rock of the Berezov Formation (West Siberia, Russia). The core samples were passed through a multiscale imaging workflow for pore-space-structure upscaling from nanometer to log scale. FIB-SEM imaging resolved the finest scale using a dual-beam analytical system. Image segmentation used an architecture derived from a convolutional neural network (CNN) in the DeepUNet (Ronneberger et al. 2015) configuration. We implemented the solution in the Pytorch® (Facebook, Inc., Menlo Park, California, USA) framework in a Linux environment. Computation exploited a high-performance computing system. The acquired data included three 3D FIB-SEM data sets with a physical size of approximately 20 × 15 × 25 µm with a voxel size of 5 nm. A professional geologist manually segmented (labeled) a fraction of slices. We split the labeled slices into training, validation, and test data. We then augmented the training data to increase its size. The developed CNN delivered promising results. The model performed automatic segmentation with the following average quality indicators according to test data: accuracy of 86.66%, precision of 54.93%, recall of 83.76%, and F1 score of 55.10%. We achieved a significant boost in segmentation speed of 14.5 megapixel (MP)/min. Compared with 0.18 to 1.45 MP/min for manual labeling, this yielded an efficiency increase of at least 10 times. The presented research work improves the quality of quantitative petrophysical characterization of complex reservoir rocks using digital rock imaging. The development allows the multiphase segmentation of 3D FIB-SEM data complicated with artifacts. It delivers correct and precise pore-space segmentation, resulting in little turn-around-time saving and increased porosity-data quality. Although image segmentation using CNNs is mainstream in the modern ML world, it is an emerging novel approach for reservoir-characterizationtasks.

scholarly journals Research of Temperature Conditions of Organic Sediments Formation in the Productive Formation at Paraffinic Oil Well Production

2021 ◽  
Vol 21 (2) ◽  
pp. 84-93
Author(s):  
Mikhail S. Sandyga ◽  
◽  
Ivan A. Struchkov ◽  
Mikhail K. Rogachev ◽  
◽  
...  
Keyword(s):  
Free Volume ◽  
Pore Space ◽  
Experimental Studies ◽  
Saturation Temperature ◽  
Reservoir Rock ◽  
Core Material ◽  
Reservoir Rocks ◽  
Temperature Conditions ◽  
Before And After ◽  
Paraffinic Oil

The paper presents the studies results of the temperature conditions for the formation of organic (asphalt-resin-paraffinic) deposits in the productive formation during the downhole production of paraffinic oil, including the results of experimental studies to assess the temperature of oil saturation with paraffin in the pore space of reservoir rocks. The studies were carried out in order to substantiate and develop a technology for preventing such deposits in the "reservoir - well" system. The results of filtration and rheological studies showed that for the same oil, the wax saturation temperature in the pore space of the reservoir rock could exceed the value of this parameter in the free volume. It was found that for the investigated solutions (models of highly paraffinic oils), the phase transition of paraffin from liquid to solid state, the formation of wax crystals in the pore space occured at a temperature 3-4° C higher than in the free volume. The results of tomographic studies of the core material, performed before and after filtration of a paraffin-containing solution through it with a decrease in temperature, showed that the open porosity of rock samples decreased on average four times due to the clogging of their pore space with paraffin. Based on the results of the filtration experiment and computed tomography, a digital core model was created, which allowed modeling the fluid flow in the pore space of the rock before and after the formation of paraffin deposits in it. The calculations results of the changes dynamics in the thermal field around the injection well confirmed the probability of cooling the bottomhole zone of the well to a temperature equal to the temperature of the onset of wax crystallization, as well as the probability of the cold water front advancing to neighboring production wells, which could cause a significant decrease in the productivity due to the formation of paraffin deposits in pore space of reservoir rocks. The research results are recommended to be taken into account when developing oil fields in conditions of possible formation of organic (asphalt-resin-paraffinic) deposits in the productive formation. This will make it possible to more reliably predict and effectively prevent its formation in the "reservoir - well" system.

Laboratory studies of oil-washing characteristics of surfactants in the pore space of reservoir rocks

2021 ◽  
pp. 86-98
Author(s):  
V. Yu. Ogoreltsev ◽  
S. A. Leontiev ◽  
A. S. Drozdov
Keyword(s):  
Oil Recovery ◽  
Pore Space ◽  
Oil Field ◽  
Oil Fields ◽  
Molecular Surface ◽  
Laboratory Studies ◽  
Reservoir Rocks ◽  
Technological Efficiency ◽  
Chemical Eor ◽  
Physical And Chemical

When developing hard-to-recover reserves of oil fields, methods of enhanced oil recovery, used from chemical ones, are massively used. To establish the actual oil-washing characteristics of surfactant grades accepted for testing in the pore space of oil-containing reservoir rocks, a set of laboratory studies was carried out, including the study of molecular-surface properties upon contact of oil from the BS10 formation of the West Surgutskoye field and model water types with the addition of surfactants of various concentrations, as well as filtration tests of surfactant technology compositions on core models of the VK1 reservoir of the Rogozhnikovskoye oil field. On the basis of the performed laboratory studies of rocks, it has been established that conducting pilot operations with the use of Neonol RHP-20 will lead to higher technological efficiency than from the currently used at the company's fields in the compositions of the technologies of physical and chemical EOR Neonol BS-1 and proposed for application of Neftenol VKS, Aldinol-50 and Betanol.

scholarly journals Groundwater Chemistry of Some Selected Areas in Southeastern Norway

1980 ◽  
Vol 11 (1) ◽  
pp. 33-54 ◽  
Author(s):  
Jens-Olaf Englund ◽  
Jan Aug Myhrstad
Keyword(s):  
Land Surface ◽  
Mineral Water ◽  
Sea Water ◽  
Electrical Conductance ◽  
Reservoir Rock ◽  
Rock Fractures ◽  
Sea Salts ◽  
Reservoir Rocks ◽  
Rock Types ◽  
Groundwater Samples

Within three areas in Southeastern Norway, Lake Mjøsa district, Ås and Moss - Jeløy, groundwater samples for chemical analysis were collected during the years 1971–77 from 98 drilled wells in bedrocks. The water was taken at depths ranging from 15 m to 110 m below the land surface. The groundwater surface is usually present well below the overlying unconsolidated deposits of glacial, glacifluvial or marine origin. The movement of groundwater within the aquifers investigated is so slow that regional changes in water quality is not only dependent on weathering in the unsaturated zone, but also dependent on the solution of reservoir rocks below the groundwater surface. Variations in specific electrical conductance (20°C) largely reflects the different reservoir rock types. The highest values, around 550 μS/cm, are typically found in dark calcareous shales, while sandstones and gneisses give values around 300 μS/cm. The areas Ås and Moss-Jeløy are situated below the Late-Postglacial marine limit. The groundwater is here more or less influenced by ancient sea salts, perhaps also by fossil sea water, left over in sediments or in rock fractures. Brackish groundwater was also found. The composition of groundwater is largely governed by mineral-water equilibria. Most investigated water samples have not reached equilibrium with their surrounding minerals.

Adsorption/Desorption of Sulfonate by Reservoir Rock Minerals in Solutions of Varying Sulfonate Concentrations

1985 ◽  
Vol 25 (03) ◽  
pp. 343-350 ◽  
Author(s):  
P. Somasundaran ◽  
H. Shafick Hanna
Keyword(s):  
Surfactant Concentration ◽  
Memory Effects ◽  
Reservoir Rock ◽  
Complex Nature ◽  
Reservoir Rocks ◽  
Batch Type ◽  
Surfactant Solutions ◽  
Major Interest ◽  
Considerable Work ◽  
Rock Minerals

Abstract In micellar flooding, reservoir rocks are exposed to surfactant solutions of varying concentrations as the surfactant slug advances through the reservoir. Therefore, the attachment and detachment of sulfonates with rocks that are already exposed to surfactant solutions of higher or lower concentrations is of major interest. In this study, the abstraction behavior of purified Na-dodecylbenzenesulfonate on Na-kaolinite by stepwise increase in surfactant concentration is determined. Deabstraction* occurring after reductions in surfactant concentrations at various stages also is determined. Most importantly, the results of incremental abstraction, individual abstraction, and deabstraction showed the system to exhibit hysteresis or memory effects. Also, abstractions obtained at various pH values and during stepwise changes in pH exhibited marked differences. The deabstraction isotherms showed the presence of maximum in certain cases, indicating the occurrence of maximum on the abstraction isotherms to be a real phenomenon. Possible reasons for the hysteresis are phenomenon. Possible reasons for the hysteresis are considered, and the practical implications of these memory effects on micellar flooding and depletion experiments using cores are discussed. Introduction Loss of surfactants owing to their interactions with reservoir rocks and fluid is possibly the most important factor that can determine the efficiency of a micellar flooding process. While there has been considerable work with process. While there has been considerable work with dilute surfactant solutions, mechanisms by which surfactants interact with rocks in their critical micelle concentration (CMC) range have not been studied in detail. Nevertheless, some limited data that have been reported in the literature do suggest that the adsorption characteristics of systems made up of concentrated surfactant solutions (above the CMC) are markedly different from those of systems involving dilute solutions. Adsorption isotherms above CMC have been reported to exhibit shapes that have not been encountered elsewhere. Our past work on abstraction of dodecylbenzenesulfonate on Na-kaolinite clearly showed the complex nature of the process, which depends on a number of system variables such as the nature and concentration of inorganic electrolytes, surfactant concentration, pH, and temperature. Under certain conditions, the systems exhibited a maximum in the region of CMC and, in some cases, a minimum at higher concentrations. Most interestingly, the presence of the maximum in the abstraction isotherm depended strongly on the type of inorganic electrolyte in the system. From a practical point of view, it would indeed be useful to be able to control the abstraction of sulfonates by rock minerals by controlling the inorganic electrolytes in the system. However, laboratory batch-type adsorption tests cannot be used directly for micellar flooding systems for a number of reasons. One important consideration in this regard is that the reservoir rocks are exposed to surfactant solutions of varying concentration as the surfactant slug advances through the reservoir. To examine the role of this effect, the abstraction behavior of sulfonates by kaolinite during incremental increase and decrease in surfactant concentration has been determined in this study. Comparison of the abstraction isotherms obtained by conventional batch-type tests (B-isotherms) with those obtained by stepwise changes in surfactant concentration (S-isotherms) and the deabstraction of isotherms of sulfonate upon dilution of the system should help in developing an understanding of the surfactant abstraction behavior as well as the phenomenon of abstraction maximum. Materials and Methods Kaolinite Kaolinite used was a well-crystallized Georgia sample with a B.E.T. surface area of 9.8 m2/g [105 sq ft/g]. Homoionic Na-kaolinite prepared according to a procedure described earlier was used for all the procedure described earlier was used for all the adsorption tests discussed here. Surfactants and Chemicals Sodium dodecylbenzenesulfonate (DDBS) purchased from Lachat Chemical Inc. (specified to be 95 % active but analyzed to be 85 %) was purified in the following manner. purified in the following manner. SPEJ P. 343

Data Assimilation of Coupled Fluid Flow and Geomechanics Using the Ensemble Kalman Filter

SPE Journal ◽  
2010 ◽  
Vol 15 (02) ◽  
pp. 382-394 ◽  
Author(s):  
Haibin Chang ◽  
Yan Chen ◽  
Dongxiao Zhang
Keyword(s):  
Fluid Flow ◽  
Kalman Filter ◽  
Data Assimilation ◽  
Material Properties ◽  
Ensemble Kalman Filter ◽  
Oil Field ◽  
Reservoir Rock ◽  
Model Parameters ◽  
Stress Strain ◽  
Reservoir Flow

Summary In reservoir history matching or data assimilation, dynamic data, such as production rates and pressures, are used to constrain reservoir models and to update model parameters. As such, even if under certain conceptualization the model parameters do not vary with time, the estimate of such parameters may change with the available observations and, thus, with time. In reality, the production process may lead to changes in both the flow and geomechanics fields, which are dynamically coupled. For example, the variations in the stress/strain field lead to changes in porosity and permeability of the reservoir and, hence, in the flow field. In weak formations, such as the Lost Hills oil field, fluid extraction may cause a large compaction to the reservoir rock and a significant subsidence at the land surface, resulting in huge economic losses and detrimental environmental consequences. The strong nonlinear coupling between reservoir flow and geomechanics poses a challenge to constructing a reliable model for predicting oil recovery in such reservoirs. On the other hand, the subsidence and other geomechanics observations can provide additional insight into the nature of the reservoir rock and help constrain the reservoir model if used wisely. In this study, the ensemble-Kalman-filter (EnKF) approach is used to estimate reservoir flow and material properties by jointly assimilating dynamic flow and geomechanics observations. The resulting model can be used for managing and optimizing production operations and for mitigating the land subsidence. The use of surface displacement observations improves the match to both production and displacement data. Localization is used to facilitate the assimilation of a large amount of data and to mitigate the effect of spurious correlations resulting from small ensembles. Because the stress, strain, and displacement fields are updated together with the material properties in the EnKF, the issue of consistency at the analysis step of the EnKF is investigated. A 3D problem with reservoir fluid-flow and mechanical parameters close to those of the Lost Hills oil field is used to test the applicability.

Sign in / Sign up

Export Citation Format

Share Document