Changes In Reservoir Properties Research Articles

Research on the application of wellbore strengthening methodology and managed pressure drilling for HTHP wells in highly depleted reservoirs at the Nam Con Son basin

The gas production in high-temperature, high-pressure (HTHP) projects in the Nam Con Son basin is entering a declining production phase, the production duration almost reaching the final phase of the designed field life. Therefore, the need to build a development plan for maintaining and supplementing gas production is the most important in the current phase. Evaluation of gas field conditions, drilling infill wells to expand existing prospects is considered a feasible solution both technically and economically. However, the physical characteristics of the production reservoirs have changed after a long production time, including a decrease in pore pressure at the production reservoirs, posing a significant technical challenge during the drilling operations. The infill wells are required to penetrate through the shale formations interbedded with sand formations. In there, the cap rock shale layer remains at or close to virgin pressure and the sand reservoir with pore and fracture pressures has largely decreased due to production activities. There is no mud-weight window that exists any more at the transition between cap rock and reservoirs which leads to drilling problems such as loss circulation, gas kicks and especially, the well could not reach the total desired depth or production targets which impact to overall development project. This article evaluates the applicability of a combination of technologies, including utilizing special lost circulation materials to seal the fractures due to changes in reservoir properties and the application of managed pressure drilling methodologies while drilling through infill wells in HTHP conditions. The goal is to minimize the risks of well problems and provide the management of uncertainties during the drilling which improves project efficiency.

Shale pore characteristics and their impact on the gas-bearing properties of the Longmaxi Formation in the Luzhou area

Deep shale has the characteristics of large burial depth, rapid changes in reservoir properties, complex pore types and structures, and unstable production. The whole-rock X-ray diffraction (XRD) analysis, reservoir physical property parameter testing, scanning electron microscopy (SEM) analysis, high-pressure mercury intrusion testing, CO2 adsorption experimentation, and low-temperature nitrogen adsorption–desorption testing were performed to study the pore structure characteristics of marine shale reservoirs in the southern Sichuan Basin. The results show that the deep shale of the Wufeng Formation Longyi1 sub-member in the Luzhou area is superior to that of the Weiyuan area in terms of factors controlling shale gas enrichment, such as organic matter abundance, physical properties, gas-bearing properties, and shale reservoir thickness. SEM is utilized to identify six types of pores (mainly organic matter pores). The porosities of the pyrobitumen pores reach 21.04–31.65%, while the porosities of the solid kerogen pores, siliceous mineral dissolution pores, and carbonate dissolution pores are low at 0.48–1.80%. The pores of shale reservoirs are mainly micropores and mesopores, with a small amount of macropores. The total pore volume ranges from 22.0 to 36.40 μL/g, with an average of 27.46 μL/g, the total pore specific surface area ranges from 34.27 to 50.39 m2/g, with an average of 41.12 m2/g. The pore volume and specific surface area of deep shale gas are positively correlated with TOC content, siliceous minerals, and clay minerals. The key period for shale gas enrichment, which matches the evolution process of shale hydrocarbon generation, reservoir capacity, and direct and indirect cap rocks, is from the Middle to Late Triassic to the present. Areas with late structural uplift, small uplift amplitude, and high formation pressure coefficient characteristics favor preserving shale gas with high gas content and production levels.

A fully coupled thermo-poroelastic model for energy extraction in naturally fractured geothermal reservoirs: sensitivity analysis and flow simulation

The development of a novel method for modelling fluid flow and heat transfer in naturally fractured geothermal reservoirs represents a significant advancement in geothermal energy research. This Study presents a hybrid approach, which combines discrete fracture and single continuum techniques, to effectively capture the complex interactions between fluid flow and heat transfer in geothermal fractured reservoirs. In addition, the incorporation of the local thermal nonequilibrium method for simulating heat transmission accounts for the disparities in temperature between the rock matrix and the fluid, providing a more realistic representation of heat transfer processes. The study also presents a fully coupled thermo-poro-elastic framework that integrates fluid flow and heat transfer to comprehensively evaluate reservoir responses to injection/production scenarios. This coupled approach allows for the prediction of changes in reservoir properties, such as permeability and porosity, under varying fluid pressure and temperature conditions. The application of the proposed model to evaluate a geothermal reservoir’s long-term response to injection/production scenarios provides valuable insights into the reservoir’s behaviour and potential energy production capacity. The sensitivity analysis further enhances the model’s utility by identifying the key reservoir parameters that significantly influence the thermal depletion of the reservoir. Overall, this novel modelling approach holds promise for improving the understanding and management of naturally fractured geothermal reservoirs, contributing to the optimization of geothermal energy extraction strategies.

Lithofacies, changes in mineral composition and reservoir properties of the Maykopian sediments in the Yevlakh-Aghjabedi Depression

Yevlakh-Aghjabadi depression is a well explored oil province located in the Middle Kura basin between Greater and Lesser Caucasus.The study investigates the lithofacial, mineralogical, and collector properties of the Maykopian sedimentary series within the Yevlakh-Aghjabadi depression, focusing on the Oligocene to Early Miocene epoch. Maykop deposits are widely distributed in the foothill regions of the Lesser Caucasus, both at the surface as natural outcrops and in the geological structure of deeper formations. In this article, in addition to core samples, the results of fieldworks have also been widely discussed. The conducted research indicates favorable paleogeographic conditions for oil and gas presence in these depressions. The sedimentary sequence, up to 2200 meters thick, is divided into Lower and Upper Maykopian subgroups, showing fluctuating thickness distribution. The primary source of clastic materials for the Maykopian suit is the Lesser Caucasus Mountain range. The lithological composition consists of clay, sandstones, and conglomerates, influenced by paleogeographic changes and paleochannels. Collector properties vary, with Lower Maykopian sediments exhibiting better characteristics, especially in the south-western part of the basin. The mineralogical composition dominated by fine-grained feldspars, impacts reservoir quality. Maykopian suits in the oil and gas regions of Ganja and Muradkhanli, which encompass the southernwestern and northern-eastern flanks of the Yevlakh-Aghjabedibasin, as well as conducting extensive research on reservoir properties, will enable the proper direction of future exploration activities. For this purpose, the overall condition of the Maykopian suits and the distribution of lithofacies have been analyzed, and the characteristics of hydrocarbon reservoirs have been determined. Keywords: lithology; lithofacies; Maykopian; sandy and clayey sediments; argillaceous sandstones; porosity; permeability.

Quantitative pressure and saturation engineering values from 4D PP and PS seismic data

AbstractFor field development and drilling decisions, production assets and reservoir engineers require dynamic reservoir properties, such as saturation and pressure changes of a reservoir from the pre‐production virgin state. To date, geophysicists have produced time‐lapse (4D) seismic attributes (mostly on stacked seismic data) rather than dynamic parameters directly. In this paper, we present a new method to estimate saturation and pressure properties from time‐lapse seismic data to provide to reservoir engineers. This new three‐step method is demonstrated over the Edvard Grieg field in the North Sea. We can realize this method thanks to advanced seismic multi‐component acquisition via PP and PS seismic data and processing that allows accurate estimation of amplitude‐variation‐with‐offset parameters P‐ and S‐impedances. With time‐lapse P‐ and S‐impedances optimally resolved, we estimate a stable set of axes identifying water saturation increase (water replacing oil), gas saturation increase (gas injection or gas out of solution), pressure increase (at injectors) and pressure decrease (at producers). Once these axes are obtained, we convert every 4D P‐ and S‐impedance data points into 4D pseudo‐saturation and pseudo‐pressure using a transformation of coordinates. We next use the rock physics relationships of this field to show that a linear relationship can be used to map any 4D change in the field from impedances to saturations and pressures. Key locations in the field with largest saturation and pressure changes are used to find calibration values at these extreme points. Next, from the pseudo‐seismic 4D data, a linear mapping is used to calculate actual reservoir property changes (fractions for saturation and bars for pressure). This allows us to obtain fieldwide dynamic values for water and gas saturations and injection and production related pressure changes. The results are shown, and dynamic changes are interpreted on the Edvard Grieg field data.

ГЕОХИМИЧЕСКИЕ ПОСЛЕДСТВИЯ ЗАХОРОНЕНИЯ УГЛЕКИСЛОГО ГАЗА В ТЕРРИГЕННЫХ КОЛЛЕКТОРАХ

The paper is aimed at the research practice on identifying the features of interaction in the water-rockcarbon dioxide system in relation to terrigenous reservoirs, widely occurring in hydrogeological basins in the territory of the Russian Federation and potentially suitable for the placement of carbon dioxide. As the CO2 solution is saturated, along with an increase in total dissolved solids there is a naturally-determined increment in the volume of transition of ions into their complex forms. The main macro components (Ca2+, Mg2+, Na+, K+, (SO4)2–, Cl– ) migrate mainly in the form of their own ions, with a decrease in their fraction by an order of 1–3 % with an increase in mineralization. Ions such as Fe, Al3+, Mn3+, (NO3)–, (HCO3)–, SiO2, (NH4)+, (NO2)– are prone to transition into the form of complex compounds, the fraction of which in the total volume increases with the amount of saturation of solution with carbon dioxide. When CO2 is injected into the terrigenous reservoir, there is a natural decrease in the solution pH, absence of precipitation of carbonates and minimal changes in the rock porosity. The observed process of dissolution of primary aluminosilicate minerals (albite, anorthite, potassium feldspar) is characteristic of most of the considered mineralogical varieties of reservoirs, when they are saturated with CO2. This process is accompanied by deposition of secondary mineral phases in the form of montmorillonites, illites, chlorites, etc. Taking into account the low rates of these reactions, no significant changes in reservoir properties are noticed.

Effects of Changes in Physical Properties of Porous Media and Fluid under Supercritical CO2 Huff-n-Puff in Low-Permeability Reservoir

The low-permeability reservoirs have abundant reserves and broad development prospects, and the supplementary energy methods have gradually become a hot research topic. In addition, the technology of enhanced oil recovery through supercritical CO2 injection is becoming increasingly mature; however, the changes in reservoir properties at the microscopic level still need further investigation. In this study, natural rock cores from low-permeability reservoirs were used to simulate reservoir conditions and conduct supercritical CO2 injection experiments for energy supplementation. The study aimed to investigate the changes in reservoir microstructure, minerals, and crude oil properties before and after the experiments. The research results indicate that after supercritical CO2 injection into the reservoir, it dissolves in the formation water to form carbonic acid. Under the effect of dissolution, the porosity of the low-permeability reservoir increases by 1.06–5.68%, and permeability can be improved by 40–60%. The rock becomes more water-wet and less oil-wet. The content of calcite and feldspar in the rock minerals decreases due to the dissolution of carbonic acid, resulting in a reduction in plagioclase and calcite. After the CO2 injection, the light components (C8–C10) in the crude oil in the rock cores decreased by approximately 14.6%, while the heavy components (C16–C39) increased by 6.99%. The viscosity of the crude oil decreases, and its flowability is further enhanced.

Effects of acid–rock reaction on physical properties during CO2-rich industrial waste gas (CO2-rich IWG) injection in shale reservoirs

"Carbon peaking and carbon neutrality" is an essential national strategy, and the geological storage and utilization of CO2 is a hot issue today. However, due to the scarcity of pure CO2 gas sources in China and the high cost of CO2 capture, CO2-rich industrial waste gas (CO2-rich IWG) is gradually emerging into the public's gaze. CO2 has good adsorption properties on shale surfaces, but acidic gases can react with shale, so the mechanism of the CO2-rich IWG–water–shale reaction and the change in reservoir properties will determine the stability of geological storage. Therefore, based on the mineral composition of the Longmaxi Formation shale, this study constructs a thermodynamic equilibrium model of water–rock reactions and simulates the regularity of reactions between CO2-rich IWG and shale minerals. The results indicate that CO2 consumed 12% after reaction, and impurity gases in the CO2-rich IWG can be dissolved entirely, thus demonstrating the feasibility of treating IWG through water–rock reactions. Since IWG inhibits the dissolution of CO2, the optimal composition of CO2-rich IWG is 95% CO2 and 5% IWG when CO2 geological storage is the main goal. In contrast, when the main goal is the geological storage of total CO2-rich IWG or impurity gas, the optimal CO2-rich IWG composition is 50% CO2 and 50% IWG. In the CO2-rich IWG–water–shale reaction, temperature has less influence on the water–rock reaction, while pressure is the most important parameter. SO2 has the greatest impact on water–rock reaction in gas. For minerals, clay minerals such as illite and montmorillonite had a significant effect on water–rock reaction. The overall reaction is dominated by precipitation and the volume of the rock skeleton has increased by 0.74 cm3, resulting in a decrease in shale porosity, which enhances the stability of CO2 geological storage to some extent. During the reaction between CO2-rich IWG–water–shale at simulated temperatures and pressures, precipitation is the main reaction, and shale porosity decreases. However, as the reservoir water content increases, the reaction will first dissolve and then precipitate before dissolving again. When the water content is less than 0.0005 kg or greater than 0.4 kg, it will lead to an increase in reservoir porosity, which ultimately reduces the long-term geological storage stability of CO2-rich IWG.

Evolution of reservoir properties of oil shale rocks under hydro-thermal treatment: Investigations from micro- to macro-scale

Treatment with water at sub- and supercritical states which is considered as one of the most promising technologies for oil shale reservoirs development is still understudied. In particular, reliable correlations between most of the reservoir properties and temperature are absent. However, this data may significantly improve the quality of oil recovery predictions applying numerical simulations. This work is devoted to obtaining the dependency between porosity, permeability, organic matter content and temperature through physical modeling of hydrous pyrolysis. A unique experimental program design is proposed to investigate changes in reservoir properties at macro- and micro-scales and connect these changes with composition and pore structure evolution. A set of experiments on hydrous pyrolysis in a closed system was performed at temperatures 110, 250, 300,325, 350, 375, 400, and 450 °C, and the pressure of 23.4 MPa on rock samples of the Bazhenov formation.As a result, the relation between reservoir properties and the temperature was derived, characterized by a few specific temperature zones with particular behaviors of rock porosity and permeability. Effects on reservoir properties were analyzed in a complex way to highlight the mechanisms of void space transformation related both with pore space evolution and reduction. The observed effects include thermal expansion of organic matter with further transformation to synthetic hydrocarbons, formation of new mineral components, mineral matrix swelling and fracturing.

Peculiarities of the study of pre-gas-hydrate deposits

A quantitative measure of well productivity is the productivity factor. Its value is determined by many factors, but especially by filtration-volume parameters of the zone immediately adjacent to the bottomhole.Filtration-capacitive properties of these zones are formed mainly at the stage of penetration and development of productive object. The practice shows that the present set of technological measures, which characterize the completion cycle, largely determines the reduction of filtration characteristics of the reservoir in the near-wellbore area.Often the consequences are so severe that even from highly permeable intervals it is not possible to obtain commercially viable flows of formation fluid.Under conditions of annually growing volumes of drilling and oil and gas production, old technological methods and schemes are no longer satisfying production. Today there is an urgent need to find and develop new, highly effective methods of drilling, production, field development, allowing meeting the needs of the domestic economy in hydrocarbons.The process of well completion plays an important role in this process. Promising in this area should be considered such a set of measures, which allows preventing or eliminating the negative impact of the cycle of well construction on the productive capacity of the reservoir to the greatest extent.In this regard, the right choice of technical or technological solutions is largely conditioned by the availability of information about the degree of their influence on the change in reservoir properties.

An Integrated Workflow for the Probabilistic Estimation of Pressure and Saturation Changes from 4D Seismic Data: Application to the Catcher Fields, Central North Sea

We present 4D seismic inversion to reservoir pressure and saturation changes applied to data from the Catcher fields. The inversion workflow integrates data from reservoir simulation, well logs and production volumes, time-lapse time shifts and angle-stacked 4D seismic amplitudes as well as machine learning and Bayesian inversion methods. It begins with a petro-elastic model and reservoir pressure sensitivity calibration step, using well log data and time-lapse time-shifts. A machine learning inversion is then used to create an initial estimate of the reservoir property changes. This estimate is then used as prior information, in conjunction with reservoir simulation pressure data, for a stochastic Bayesian inversion workflow. We show that the Bayesian inversion benefits from the use of machine learning prior, leading to improvements in the match to the observed 4D seismic signal as well as the injected and produced water volumes. In addition to a most probable solution, stochastic sampling of the Bayesian posterior distribution also produces uncertainty estimates which are valuable in such inversion problems. With this result, we extract multiple equiprobable realisations and define conditional bounds for the pressure and saturation changes, which we recognise as helpful for reservoir management and 4D seismic data assimilation into reservoir simulation models.

Pore-scale study of microbial hydrogen consumption and wettability alteration during underground hydrogen storage

Hydrogen can be a renewable energy carrier and is suggested to store renewable energy and mitigate carbon dioxide emissions. Subsurface storage of hydrogen in salt caverns, deep saline formations, and depleted oil/gas reservoirs would help to overcome imbalances between supply and demand of renewable energy. Hydrogen, however, is one of the most important electron donors for many subsurface microbial processes, including methanogenesis, sulfate reduction, and acetogenesis. These processes cause hydrogen loss and changes of reservoir properties during geological hydrogen storage operations. Here, we report the results of a typical halophilic sulfate-reducing bacterium growing in a microfluidic pore network saturated with hydrogen gas at 35 bar and 37°C. Test duration is 9 days. We observed a significant loss of H2 from microbial consumption after 2 days following injection into a microfluidic device. The consumption rate decreased over time as the microbial activity declined in the pore network. The consumption rate is influenced profoundly by the surface area of H2 bubbles and microbial activity. Microbial growth in the silicon pore network was observed to change the surface wettability from a water-wet to a neutral-wet state. Due to the coupling effect of H2 consumption by microbes and wettability alteration, the number of disconnected H2 bubbles in the pore network increased sharply over time. These results may have significant implications for hydrogen recovery and gas injectivity. First, pore-scale experimental results reveal the impacts of subsurface microbial growth on H2 in storage, which are useful to estimate rapidly the risk of microbial growth during subsurface H2 storage. Second, microvisual experiments provide critical observations of bubble-liquid interfacial area and reaction rate that are essential to the modeling that is needed to make long-term predictions. Third, results help us to improve the selection criteria for future storage sites.

O wpływie zjawiska kolmatacji na wydajność odwiertu

"During the opening of a productive formation by drilling, penetration of clay particles from the drilling fluid into the leading filtration channels of the rock occurs. As a rule, productive formations are opened at pressures that are significantly higher than the formation pressure. The amount of hydrostatic repression depends on the density of the drilling fluid, the height of the liquid column, and the reservoir pressure. A classic example of the latter is the problem of studying changes in reservoir properties that occur at the drilling stage, where relatively small particles of drilling fluid penetrate along with the flow into the pore space. A decrease in the bottomhole zone permeability in oil wells leads to a significant decrease in oil production rates, and sometimes to their complete stop, which ultimately significantly affects the total oil recovery and economic indicators of the oil fields’ development. The decrease in permeability can be caused by many factors: – clogging of the bottomhole zone of the productive formation in the process of drilling a well; – formation of a crust in perforated channels during cumulative perforation; – colmatation of the bottomhole zone of the productive formation during the operation of the well; – clogging of perforated channels during well killing and subsequent clogging; – formation of deposits of paraffins and asphaltenes in the pores of the rock of the bottomhole zone of the well. Bottomhole zone damage (clogging) significantly affects the productivity of wells, and the permeability of the formation, determined by the results of hydrodynamic studies. At the same time, clogging is understood as damage of the bottomhole zone with drilling fluid when opening the productive formation, and deterioration of the properties of the bottomhole zone during cementing, perforation of the productive interval, swelling of clays, etc. This paper presents an analysis of laboratory and field studies of the influence of clogging on the productivity of wells when opening layers with different capacitive and filtration properties, and also provides an analytical estimation of this effect, both for vertical and horizontal wells."

Four-Dimension Seismic Analysis in Carbonate: A Closed Loop Study

Four-dimensional seismic analysis is an effective reservoir surveillance tool to track the changes of fluid and pressure phases in the oil and gas reservoirs over time of the baseline and monitoring seismic acquisition. In practice, the 4D seismic signal associated with such changes may be negligible, especially in heterogeneous carbonate reservoirs. Therefore, 4D seismic analysis is a model for integrating various disciplines in the oil and gas industry, such as seismic, petrophysics, reservoir engineering, and production engineering. In this study, we started the 4D seismic workflow with a 1D well-based 4D feasibility study to detect the likelihood of 4D signals before performing 4D seismic co-processing of the baseline and monitoring surveys starting from the seismic field data of both datasets. As part of a full 4D seismic co-processing of the baseline and monitor surveys, 4D seismic metric attributes were analyzed over the survey area to measure the improvement in seismic acquisition repeatability for the scarce 1994 baseline seismic and the 2014 monitor seismic survey. For the monitor survey, a 4D time-trace shift was performed using the baseline survey as a reference to measure the time shifts between the baseline and monitor surveys at 20-year intervals. The 4DFour-dimensional dynamic trace warping was followed by a 4D seismic inversion to compare the 4D difference in the seismic inverted data with the difference in seismic amplitude. The seismic inversion helped overcome noise, multiple contaminations, and differences in dynamic amplitude range between the baseline and monitor seismic surveys. We then examined the relationship between well logs and seismic volumes by predicting a volume of log properties at the well locations of the seismic volume. In this method, we computed a possibly nonlinear operator that can predict well logs based on the properties of adjacent seismic data. We then tested a Deep Feed Forward Neural Network (DFNN) on six wells to adequately train and validate the machine learning approach using the baseline and monitoring seismic inverted data. The objective of trying such a deep machine learning approach was to predict the density and porosity of both the baseline and the monitoring seismic data to validate the accuracy of the 4D seismic inversion and evaluate the changes in reservoir properties over a time-lapse of 20 years of production from 1994 to 2014. Finally, we matched the 4D seismic signal with changes in reservoir production properties, investigating the mechanism underlying the observed 4D signal. It was found that the detectability of 4D signals is primarily related to changes in fluid saturation and pressure changes in the reservoir, which increased from 1994 to 2014. This innovative closed-loop research proved that the low repeatability of seismic acquisition can be compensated by optimal 4D seismic co-processing with a complete integration workflow to assess the reliability of the 4D seismic observed signal.

Reservoir Properties Alteration in Carbonate Rocks after In-Situ Combustion

Summary This study summarizes the work conducted as a part of laboratory modeling of in-situ combustion (ISC) experiments on cores from carbonate heavy oil fields. Porosity, permeability, fluid saturation, thermal, and geochemical properties are crucial characteristics of the target field defining the performance of the combustion technology. Here, we report the changes in reservoir properties, porous structure, and mineral composition of the rock samples induced by the thermal exposure and registered by a set of standard and advanced experimental techniques. Most combustion tests are conducted on the crushed core pack, which does not accurately represent the reservoir properties. In this paper, we present the results of three combustion tube tests (classic ISC and consecutive hot-water treatment ISC) involving actual field core samples. Gas porosimetry, nuclear magnetic resonance (NMR), and microcomputed tomography (μCT) revealed an increase in total porosity and pore size distribution and enabled visualizing the changes in the porous core structure at nano- and microlevels. X-ray diffraction (XRD) and scanning electron microscopy (SEM) demonstrated the change in mineral composition and lithological texture as a result of dolomite decomposition; Rock-Eval pyrolysis and elemental analysis were utilized to confirm the changes in the rock matrix. Optical scanning registered the changes in thermal conductivity (TC) of samples, which is important for numerical modeling of the combustion process. The proposed core analysis has proved its efficiency in providing a complete petrophysical description of the core of a heavy oil carbonate reservoir in the framework of evaluation of the ISC application for dolomite-rich carbonates and demonstrated the different responses of rock to the ISC technology.

A machine‐learning framework to estimate saturation changes from 4D seismic data using reservoir models

Time-lapse seismic (four-dimensional seismic) data play a preeminent role in closed-loop reservoir management by providing a full-field image of dynamic reservoir behaviour during production. Nonetheless, the multidisciplinary nature of four-dimensional closed-loop approaches demands more quantitative and fast methods to integrate rock physics models, reservoir flow simulation models and four-dimensional seismic analysis. In this work, we tackle this time-consuming and expensive process and develop a data-driven quantitative approach to leverage the inherent physics between four-dimensional seismic and reservoir property changes. We propose an inversion flow method using machine learning strategies to estimate changes in reservoir properties directly from a fast-derived four-dimensional seismic attribute. This study was carried out in a Brazilian deep-water field where production started in 2013 with 3 years of production and injection history. For this reservoir, the estimation of fluid saturation maps is a critical objective to assist engineers with data assimilation procedures. We also generated millions of training data samples using 200 simulation models from the field mentioned above (before history matching) to highlight the benefits of restricting training samples to proper fluid flow consistent combinations. Results demonstrate high prediction accuracy for the targeted reservoir property changes. Additionally, it provides insights for the detection of sweet spots and positioning of infill wells. We significantly simplify the four-dimensional seismic integration process, allowing initial engagements of reservoir engineers with decision-making processes and data assimilation applications.

A real-world impact of offset frac-hits by rate transient analysis in the Bakken and Three Forks, North Dakota, USA

Production via multi-fractured horizontal wells with specific spacing units is a common development plan in shale plays. Commonly, operators drill and complete a single well in order to hold a 1280-acre spacing unit and once the acreage is secured across the asset, infill wells at each spacing unit are drilled so, depletion from the original (parent) well can be observed within the spacing unit. This will increase the likelihood of existing wells to experience inter-communication when infill wells are hydraulically fractured which has detrimental effects. Hence, understanding the effects of well timing and spacing on the performance of the overall spacing unit is critical to choose an appropriate development plan. In this regard, rate transient analysis (RTA) is an effective way to quantify the impact of offset frac-hits, hinting the changes in reservoir properties such as stimulated reservoir volume (SRV) and well productivity. In this real-world study, we used pseudo normalized pressure versus material balance square root of time plots to determine the impact of offset frac-hits on existing wells in Williston Basin, ND. The slope of the superposition time plot is inversely proportional to the product of the contacted surface area (Ac) and the square root of reservoir permeability (k), Ack, which was a good metric to evaluate early time productivity and completion effectiveness. Additionally, production look-back performed on 71 operating wells using decline curve analysis (DCA) confirmed changes in reservoir properties and production performance to determine appropriate well spacing and infill timing. Next, economic analysis for 71 wells and 13 spacing units, using a reasonable/favorable commodity pricing, to assess the investment efficiencies of each project was carried out. Results showed that offset frac-hits cause up to 50% estimated ultimate recovery (EUR) loss, up to 80% water-cut increment, and more than 40%, Ack reduction for parent wells. Wells with multi-sleeve single ball (MSSB) completion system would have 32% lower cumulative oil production per lateral foot and 50% lower EUR than open hole sliding sleeve and cemented liner plug and perf (P-n-P). Finally, more proppant and fracturing fluid volume loading not only will not increase the production, but also deteriorates well performance. Collectively, this study indicated that 5–6 wells per 1280-acre spacing is the optimal well spacing unit within the study area to set a guideline for successful future operations. Ultimately, the very detailed field practical aspects presented here which is limited in the literature and combined with theories of RTA, can become a benchmark for further verification of mathematical models.

Investigation of Time-Lapse Changes with DAS Borehole Data at the Brady Geothermal Field Using Deconvolution Interferometry

Distributed acoustic sensing (DAS) has great potential for monitoring natural-resource reservoirs and borehole conditions. However, the large volume of data and complicated wavefield add challenges to processing and interpretation. In this study, we demonstrate that seismic interferometry based on deconvolution is a convenient tool for analyzing this complicated wavefield. We also show the limitation of this technique, in that it still requires good coupling to extract the signal of interest. We extract coherent waves from the observation of a borehole DAS system at the Brady geothermal field in Nevada. The extracted waves are cable or casing ringing that reverberate within a depth interval. These ringing phenomena are frequently observed in the vertical borehole DAS data. The deconvolution method allows us to examine the wavefield at different boundary conditions and separate the direct waves and the multiples. With these benefits, we can interpret the wavefields using a simple 1D string model and monitor its temporal changes. The velocity of this wave varies with depth, observation time, temperature, and pressure. We find the velocity is sensitive to disturbances in the borehole related to increasing operation intensity. The velocity decreases with rising temperature. The reverberation can be decomposed into distinct vibration modes in the spectrum. We find that the wave is dispersive and the fundamental mode propagates with a large velocity. This interferometry method can be useful for monitoring borehole conditions or reservoir property changes using densely-sampled DAS data.

Development of an analytical model to predict oil reservoirs performance using mechanical waves propagation

The mechanical waves have been used as an unconventional enhanced oil recovery technique. It has been tested in many laboratory experiments as well as several field trials. This paper presents a robust forecasting model that can be used as an effective tool to predict the reservoir performance while applying seismic EOR technique. This model is developed by extending the wave induced fluid flow theory to account for the change in the reservoir characteristics as a result of wave application. A MATLAB program was developed based on the modified theory. The wave’s intensity, pressure, and energy dissipation spatial distributions are calculated. The portion of energy converted into thermal energy in the reservoir is assessed. The changes in reservoir properties due to temperature and pressure changes are considered. The incremental oil recovery and reduction in water production as a result of wave application are then calculated. The developed model was validated against actual performance of Liaohe oil field. The model results show that the wave application increases oil production from 33 to 47 ton/day and decreases water-oil ratio from 68 to 48%, which is close to the field measurements. A parametric analysis is performed to identify the important parameters that affect reservoir performance under seismic EOR. In addition, the study determines the optimum ranges of reservoir properties where this technique is most beneficial.

Petrophysical characteristics of the Meso-Cenozoic sediments of the Southeastern subsidence of the Greater Caucasus in connection with their oil and gas potential

In order to assess the prospects for oil and gas potential, the reservoir properties of Mezozoy-Kaynazoic sediments, formed in various geological conditions of the structures of Yalama, Khudat and Siazan monocline, have been studied. The results of the analysis are summarized in tables reflecting the physical and reservoir properties of various types of rocks. On the basis of petrophysical analysis for reservoirs of various lithological types, regularities have been established in changes in density, carbonate content, porosity and permeability of rocks, as well as in the propagation velocity of ultrasonic waves. It was found that changes in reservoir properties of rocks over the area are mainly associated with lithogenesis conditions, with heterogeneity of the lithological composition of sedimentary complexes, with the depth of occurrence of rocks, as well as with the peculiarity of the development of local uplifts. When predicting oil and gas content in deep-seated strata of the territory under consideration, along with exploration and geophysical methods, it is also recommended to use the results of changes in the filtration-volume characteristics of rocks, as well as the nature of the change in the propagation velocity of seismic waves with depth. Keywords: lithological facies; density; porosity; permeability; carbonate content; seismic P-wave velocity.