Selection of chemical agents for workover fluids hydrophobizing the pore space of reservoir rocks

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.

From the perspective of economy and safety, balancing gas contained in the pore space of rocks is extremely essential, predominantly to establishments dealing with extraction of mineral resources. One of the main methods of evaluating the amount and composition of gas contained in the pore space of a rock is releasing the gas as a result of comminuting the investigated rock material. In the case of cupriferous rocks, effective comminution is a very difficult task, due to the strength properties of these rocks. The present paper discusses the results of studies into the gas content of cupriferous rocks, obtained by means of an original device named the GPR analyzer. The research was done on 41 samples of dolomites and anhydrites from various areas of two copper mines located in Poland: “Rudna” and “Polkowice-Sieroszowice.” For all samples, on the basis of microscope analyses performed on cuts and polished sections, the open porosity, closed porosity, and total porosity were determined. In the case of the dolomite samples, the total porosity variability fell in the range of 4.75–23.05%, and in the case of the anhydrite samples—in the range of 3.87–16.60%. The maximum gas content of the dolomite samples was 166.67 cm3/kg, and of the anhydrite samples—84.66 cm3/kg. In some of the studied samples, the presence of methane was confirmed. Toxic gases, such as H2S, were not found. The main gas in the pore space of the investigated rocks was nitrogen. Knowing the amount of the released gas and the value of the closed porosity in the investigated samples, the authors were able to estimate the pore pressure of the gas, whose maximum value was 0.583 MPa.

In the present paper, the authors discussed the functioning of their own analyzer for measuring gas contained in the pore space of high strength rocks. A sample is placed inside a hermetic measuring chamber, and then undergoes impact milling as a result of colliding with the vibrating blade of a knife which is rotationally driven by a high-speed brushless electric motor. The measuring chamber is equipped with all the necessary sensors, i.e. gas, pressure, and temperature sensors. Trial tests involving the comminution of dolomite and anhydrite samples demonstrated that the constructed device is able to break up rocks into grains so fine that they are measured in single microns, and the sensors used in the construction ensure balancing of the released gas. The tests of the analyzer showed that the metrological concept behind it, together with the way it was built, make it fit for measurements of the content and composition of selected gases from the rock pore space. On the basis of the conducted tests of balancing the gases contained in the two samples, it was stated that the gas content of Sample no. 1 was (0.055 ± 0.002) cm3 g−1, and Sample no. 2 contained gas at atmospheric pressure, composed mostly of air.

The Early Development of Knowledge About Connate Water

The article discusses the validation process of a certain method of balancing gas contained in the pore space of rocks. The validation was based upon juxtaposition of the examination of rocks’ porosity and the effects of comminution in terms of assessing the possibility of opening the pore space. The tests were carried out for six dolomite samples taken from different areas of the ‘Polkowice-Sieroszowice’ copper mine in Poland. Prior to the grinding process, the rocks’ porosity fell in the range of 0.3-14.8%, while the volume of the open pores was included in the 0.01-0.06 cm3/g range. The grinding process was performed using an original device – the GPR analyzer. The SEM analysis revealed pores of various size and shape on the surface of the rock cores, while at the same time demonstrating lack of pores following the grinding process. The grain size distribution curves were compared with the cumulative pore volume curves of the cores before grinding. In order to confirm the argument put forward in this paper – i.e. that comminution of a rock to grains of a size comparable with the size of the rock’s pores results in the release of gas contained in the pore space – the amount of gas released as a result of the comminution process was studied. The results of gas balancing demonstrated that the pore space of the investigated dolomites was filled with gas in amounts from 3.19 cm3/kg to 45.86 cm3/kg. The obtained results of the rock material comminution to grains comparable – in terms of size – to the size of the pores of investigated rocks, along with asserting the presence of gas in the pore space of the studied dolomites, were regarded as a proof that the method of balancing gas in rocks via rock comminution is correct.

Using electron microscopy methods, the effect of polymer-colloidal drilling fluids on the pore space in carbonate reservoirs of an oil and gas condensate field, was studied. It is shown that the impact of polymers included in drilling fluids changes the surface of the pore space of rocks. This affects the technology of developing oil fields and the intensification of oil production. At the same time, due to the deposition of polymer components in the pore space of the rock, the properties of the samples change. This must be taken into account when conducting petrophysical studies on samples, as well as in geophysical studies of the bottom-hole zone using methods with a small study radius. The results of morphological studies in the electron microscope of the pore space of rocks after the impact of polymer-colloidal drilling fluids, are presented. Polymer films formed from drilling fluid components are studied. It has been established that after drilling horizontal wells, the change in the wettability of the pore space is associated with the formation of a polymer film on carbonate crystals. The thickness of this film, measured by the direct method, is 60–200 µm in the studied samples. It is noted that these changes in the future can lead to errors in determining the petrophysical properties.

The Middle Devonian deposits within the Lviv Depression of the Volyn-Podillya plate are largely underexplored and are of great interest for further exploration for hydrocarbons. The presence of two discovered gas fields and the occurrence of granular and fractured reservoir rocks within the entire Lviv Depression point that the deposits of this age range are prospective for further exploration works for hydrocarbons. The authors conducted mineralogical and petrographic studies of these strata in order to study different types of reservoir rocks. Petrographic studies of terrigenous rocks showed that the reservoir rocks are composed of fine-grained and medium-grained sandstones, as well as fine-grained and coarse-grained siltstones. The matrix in these rocks is contact-porous and contact, composed of dolomitized calcite (4–19 %) and hydromica (3–13 %). Regardless of the type of matrix, the pore space in rocks is formed by intergranular spaces of 0.05 to 0.5 mm size. Siltstone-sandstone deposits represent the granular-type reservoir rocks, the filtration properties of which are formed by the intergranular space, while fractures are of subordinate importance. Terrigenous rocks form gas-bearing horizons in Middle Devonian (Eiffelian and Zhivetian) in the Lokachi field of the Lviv Depression. Carbonate rocks are represented by a wide range of lithological types from slightly dolomitized biodetrital limestones to secondary dolomites. Dolomitization and recrystallization form fracture-like microcaverns with a size of up to 0.5 mm and result in a high porosity of up to 9 %. In carbonate reservoir rocks fracturing is prevailing, while porosity has a subordinate value. Studies of the molecular composition of natural gases from reservoir rocks of the Middle Devonian of the Lokachi field showed that their predominant component is methane. Its content is 92.7–95.4 vol %. The rest of the methane homologues account for 1.45–2.16 vol %. The total share of non-hydrocarbon gases – nitrogen, carbon dioxide, helium and hydrogen are 3.102–5.082 vol %. In order to clarify the origin of the Middle Devonian gases of the Lviv Depression, further studies of the carbon, nitrogen, and hydrogen isotopic composition of these gases and the study of the generation properties of the Lower and Middle Devonian rocks of the studied region are necessary.

The phenomenon of precipitation of the insoluble salts particularly calcium carbonate and calcium sulfate, deposited from cement filtrate into a rock pore space as a potential source of formation permeability damage, was studied. The series of flow tests were run in laboratory on sandstone rock examples using cement slurry filtrate containing various additives such as extenders, dispersants, retarders and fluid loss control additives. The impact of precipitation of insoluble salts on rock permeability reduction has been evaluated on the basis of experimental results applying different analytical methods: chemical and SEM/EDAX analysis, permeability change measurement, as well as X-ray computerized tomography (CT) imaging technique. All of the three types of cement filtrates, obtained from API class G cement used in experiments, caused sandstone permeability reduction, mainly due to deposition of coprecipitated insoluble CaCO3 and CaSO4 salt crystals in the pore space. The use of cellulose derivative, as fluid loss control additive caused the most severe formation damage. Lignin derivative as retarder and synthetic polymer as dispersants if used in cement slurry composition caused less damaging effects than in case of cement slurry filtrate without additives. The permeability damage due to precipitation of CaCO3 and CaSO4 from cement slurry filtrate could be partially recovered flushing the rock with brine. INTRODUCTIONS During drilling and completion operations, the permeability of potentially productive rock formations can be significantly decreased by fluids which come in contact with the reservoir. As filtration process downhole proceeds, the filtrate, with its accompanying particles, creates an invaded zone around a wellbore. Within that zone the productivity may be reduced by physical and/or chemical change to the formation rock or fluids. Drilling mud and cement slurry are the most frequently encountered as fluids generating a filtrate which penetrates into permeable formations under a differential pressure. Muds are forming an external filter cake on the face of formation exposed to it, and a relatively shallow internal cake is formed to a few centimeters from the wellbore. The chemical composition of the majority of convenient water base muds is such that mud filtrates do not produce insoluble particulate precipitates. On the other hand, when cement slurry is pumped into a well and passes by permeable formations, the aqueous phase is squeezed into the rock pore space under relatively high differential pressure between the annular space and the formation. This cement slurry filtrate contains the various ions (Ca2+, K+, Na+, OH-, Al(OH)4-, SO42-, HCO3-) dissolved in aqueous solutions. The concentration of calcium carbonate and sulfate is often close to supersaturation which would result with deposition of insoluble calcium carbonate and/or calcium sulphate precipitate deep inside the pore space. The cement slurry additives also play a role in the formation of precipitate during the filtration process downhole. P. 631^

The wettability of reservoir rock has an important impact on the efficiency of oil recovery processes and the distribution of oil and water within the reservoir. One of the potentially useful tools for wettability measurements is nuclear magnetic resonance (NMR) and spin-lattice relaxation. More recently using NMR microscopy NIPER has developed the capability of imaging one- and two-phase fluid systems in reservoir rock at resolutions to 25 microns. Effects seen in the images of fluids within the pore space of rocks near the rock grain surfaces hinted at the possibility of using NMR microscopy to map the wettability variations at grain sites within the pore space. Investigations were begun using NMR microscopy and spin-lattice relaxation time measurements on rock/fluid systems and on well-defined fractional wet model systems to study these effects. Relaxation data has been modelled using the stretched exponential relationship recently introduced. Comparisons of the NMR microscopy results of the model system with the rock results indicate that the observed effects probably do not reflect actual wettability variations within the pore space. The results of the relaxation time measurements reveal that even in the simple model studied, the behavior of two phases is somewhat ambiguous and much more complex and requires more study.

Chemical enhanced oil recovery methods are widely used in field development. One of the methods for leveling injectivity is emulsion-based technologies. The mechanism of this technology is to create an increased filtration resistance of the most depleted reservoir intervals. To establish the actual oil-displacing characteristics of the emulsifier grades accepted for testing in the pore space of oil-containing reservoir rocks, a set of laboratory filtration studies was carried out on high-permeability core models at the AS12 horizon of the Nizhne-Sortymskoye oil field.Processing laboratory data after filtration of ready-to-use emulsions through core samples gives an increase in the oil displacement coefficient by water from 1.31 to 10.79 %. When constructing their correlation dependence, it is possible to identify the range of the final dynamic viscosity (from 5 to 9 mPa∙s) of the compositions of the emulsion-based technology, which is optimal for the most effective application on groups of AS formation.Based on the laboratory studies of rocks, it was established that carrying out geological and technical measures using the emulsifier Neftenol-NZ, which has proven itself in high efficiency from well treatments, will give a large volume of additional oil production, in comparison with the currently emulsifier Sinol-EM.

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 BS10formation 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 VK1reservoir 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.

Determination of effective stress parameters for effective CO2 permeability in deep saline aquifers: An experimental study

Oil deposits in sections of the Bashkirian stage of the Sokskaya saddle are considered. It has been established those oil-bearing limestones are represented by leached peloidal-clumpy grainstones. The rocks were formed within the shallow shelf of sedimentation basin of normal salinity. The active hydrodynamics of the aquatic environment predetermined the dense structural packing of organic residues. The migration of aggressive oil-water fluids contributed to leaching of calcite cement from grainstones. Subsequently, the pore-cavernous space was filled with oil. The introduction of edge formation waters into oil-bearing reservoirs contributed to the oxidation of oil and the manifestation of secondary diagenetic mineralization. The initial stage of waterflooding was indicated by dolomitization of reservoir rocks. Due to an increase in the partial pressure of carbon dioxide in the pore space of rocks, calcite is metasomatically replaced by diagenetic dolomite. At this stage of reservoir rock alteration, a relatively small amount of oil is recovered from oil-bearing formations. The introduction of formation waters enriched with sulfate ions into reservoir layers leads to the precipitation of gypsum-anhydrite aggregates in the pore space of oil-bearing limestones. Calcium sulfate minerals clog the pore-capacitive space of reservoir rocks, reducing their productivity. At the stage of precipitation of gypsum-anhydrite aggregates, mainly mineralized brines with an admixture of oil are extracted from reservoir rocks.

Determination of oil and water distributions in the pore space of reservoir rock is important in oil recovery. Several indirect methods, such as testing wettability of mineral surfaces, assessing capillary pressure and relative permeability behavior, and measuring electrical resistivity, have been practiced to estimate the oil and water distribution in porous rock. However, a direct method of determining liquid distributions in situ has been lacking. Cryo-scanning electron microscopy (cryo-SEM) provides a means of visualizing oil and water in the individual pore segments of a porous rock. The liquid-bearing rock is frozen and kept cold at about 100 K. The frozen sample is then fractured, coated with evaporated chromium, and examined in a scanning electron microscope. Secondary and backscattered electron images and x-ray maps of the fracture surface identify the locations of oil and water in the exposed section of the pore space. Sometimes complementary fracture surfaces can be imaged. Series of the backscattered electron images illuminate the mechanisms of oil-water displacement in strongly water-wet and mixed-wet sandstones.

Traditionally, the values of reservoir rock properties have been acquired from log data or direct measurement in a physical laboratory. Recent advances in imaging and image processing, together with improved availability of high performance computing, gave rise to digital techniques for investigating the properties of rock samples. These techniques are based on high-resolution imaging of the rock's pore space, segmentation of the images into pores and various minerals and simulation of the physical processes controlled by the desired rock properties. These techniques form the novel discipline of digital rock physics (DRP). The goal of the current work is to validate the results of DRP measurements of geophysical parameters by comparing them with the results obtained in traditional physical laboratories. This study includes eight core plugs from a Cretaceous formation, representing four reservoir rock types. Multiple sub-samples of each core plug were taken and analyzed using the digital rock physics technique. Our DRP computations are compared with the results of physical measurements of the geophysical properties on samples from Cretaceous formations. The latter measurements were conducted on regular core plugs, several cm in size, much larger than the digital rock samples used in this study. Although some of the physical data represent samples from wells different from where the digital samples used here were extracted, these physical samples cover the rock types included in the study. The geophysical property values obtained in the digital rock physics laboratory closely match the results of physical measurements.