Reservoir Characteristics Research Articles

Assessment of CO2 Sequestration Capacity in a Low-Permeability Oil Reservoir Using Machine Learning Methods

The CO2 sequestration capacity evaluation of reservoirs is a critical procedure for carbon capture, utilization, and storage (CCUS) techniques. However, calculating the sequestration amount for CO2 flooding in low-permeability reservoirs is challenging. Herein, a method combining numerical simulation technology with artificial intelligence is proposed. Based on the typical geological and fluid characteristics of low-permeability oil reservoirs in the Liaohe oilfield, the CMG 2020 version software GEM module is used to establish a model for CO2 flooding and sequestration. Meanwhile, a calculation method for the effective sequestration coefficient of CO2 is established. We systematically study the sequestration rules in low-permeability reservoirs under varying conditions of permeability, reservoir temperature, and initial reservoir pressure. The results indicate that, as the permeability and sequestration pressure of the reservoir increase, oil recovery gradually increases. The proportion of structurally bound sequestration volume increases from 55% to 60%. Reservoir temperature has minimal impact on both the recovery rate and the improvement in sequestration efficiency. Sequestration pressure primarily improves sequestration efficiency by increasing the dissolution of CO2 in the remaining oil and water. The calculation chart for the effective sequestration coefficient, developed using artificial intelligence algorithms under multi-factor conditions, enables accurate and rapid evaluation of the sequestration potential and the identification of favorable sequestration areas in low-permeability reservoirs. This approach provides valuable technical support for CO2 flooding and sequestration in pilot applications.

Application of Geostatistical Inversion Technology in Nanpu Oilfield: taking 1-5 area in the Dongyi section of Nanpu Depression as an example

Small faults are developed in Nanpu 1-5 areas of Nanpu Oilfield. Due to the influence of seismic data resolution, it is difficult to predict the spatial distribution of thin reservoirs. In addition, the structure of reservoir sand bodies is unclear. In this paper, firstly, based on seismic, logging, and production dynamic data from the work area, theoretical analysis is conducted on sequence stratigraphy, sedimentary petrology, seismic sedimentology, and development geology. On this basis, an accurate reservoir geological model is established based on geostatistical inversion technology. Finally, geological model well dilution inspection, production dynamic data inspection, and production application analysis are carried out. Research results show that: the geological model has a compliance rate of over 90% for well dilution and dynamic verification. The planar distribution characteristics of high-quality reservoirs in Nanpu 1-5 areas are accurately predicted, showing an overall high in the middle and low on the east and west sides. In response to the remaining oil enrichment areas, additional drilling and water injection measures have been deployed, forming a plan to improve the recovery rate in Nanpu 1-5 areas.

Efficient development technology of Upper Paleozoic Lower Shihezi tight sandstone gas reservoir in northeastern Ordos Basin

Abstract The Lower Shihezi Formation of the Upper Paleozoic at the northeastern margin of the Ordos Basin develops widely distributed thick massive and multilayer gas reservoirs. How to formulate an effective development policy is a difficult and hot spot. In this article, reservoir characteristics and production capacity influencing factors of the tight gas sandstone in Lower Shihezi Formation in this area are systematically studied, and optimization schemes of development measures for massive and multilayer gas reservoirs are proposed. The results show that the petrophysical characteristics of the small pore–mesopore type gas reservoir in the target layer are the best, with the average porosity, permeability, and coordination number of 7.6%, 0.74 mD, and 3.3, respectively. Thick sand body, high structural position, good petrophysical properties, and high drilling rate of sandstone are all conducive to drilling high production gas wells. Development policies for massive and multilayer gas reservoirs have been formulated: (1) the preferred well type for massive gas reservoir is vertical well + horizontal well, while the preferred well type for multilayer gas reservoir is horizontal well + stepped horizontal well; (2) the reasonable horizontal segment length of massive gas reservoir is 1,000 m, and the reasonable horizontal segment length of multilayer gas reservoir is 1,250 m; (3) similar to massive and multilayer gas reservoirs, the more the fracture stages, the higher the cumulative gas production, and the optimal fracture stage number of both gas reservoirs is 8; (4) the optimal fracture half-length and the angle between the fracture and the horizontal section are 140 m and 90°, respectively; and (5) the reasonable well spacing of vertical wells is 600 m and that of horizontal wells is 750 m. The development policy proposed in this study is suitable for the efficient development of complex tight sandstone gas reservoirs in similar areas.

Uncovering Historical Reservoir Operation Rules and Patterns: Insights From 452 Large Reservoirs in the Contiguous United States

AbstractReservoir operations are influenced by hydroclimatic variability, reservoir characteristics (i.e., size and purpose), policy regulation, as well as operators' experiences and justification. Data‐driven reservoir operation models based on long‐term historical records shed light on understanding reservoir operation rules and patterns. This study applies generic data‐driven reservoir operation models (GDROMs) developed for 452 data‐rich reservoirs with diversified operation purposes across the CONUS to explore typical operation rules and patterns. We find that the operating policies of any of these reservoirs can be modeled with a small number (1–8) of typical operation modules. The derived modules applied to different conditions of the 452 reservoirs can be categorized into five basic types, that is, constant release, inflow‐driven piecewise constant release, inflow‐driven linear release, storage‐driven piecewise constant release, and storage‐driven nonlinear (or piecewise linear) release. Additionally, a joint‐driven release module, constructed from these five basic types, has been identified. The analysis further shows the module application transition patterns featuring operation dynamics for reservoirs of different operation purposes, sizes, and locations. The typical module types can be used as “Lego” bricks to build operation models, especially for data‐scarce reservoirs. These module types and their application and transition conditions can inform Standard Operation Policy (SOP) and Hedging Policy (HP) with specific inflow, storage, and/or both conditions.

Reservoir Body Development Characteristics in Deep Carbonate Gas Reservoirs: A Case Study of the Fourth Member of the Dengying Formation, Anyue Gas Field

Reservoir Body Development Characteristics in Deep Carbonate Gas Reservoirs: A Case Study of the Fourth Member of the Dengying Formation, Anyue Gas Field

Integrated modelling of CO2 plume geothermal energy systems in carbonate reservoirs: Technology, operations, economics and sustainability

The rising CO2 content in the atmosphere calls for urgent decarbonization efforts. Carbon capture and storage (CCS) have proven effective in storing large volumes of CO2 in geological reservoirs. Nevertheless, challenges persist in identifying sustainable energy sources and efficient storage sites, especially in carbonate reservoirs. This study aims to characterize the Miocene carbonate reservoir in the Jintan Megaplatform, for CO2 storage and geothermal energy utilization. By integrating advanced technologies such as CO2 Plume Geothermal (CPG) with 3D seismic techniques, borehole analysis and numerical modelling, the study reveals the distribution of critical reservoir characteristics, including architecture, heterogeneity, karstification, fractures, porosity, permeability, temperature and pressure that are paramount for CO2 plume and energy production. The reservoir is estimated to store over 31 Gt of CO2, produce 3.824 × 1018 J of geothermal energy and ⁓44.3 GW of power. This power output can be utilized for electrification of the CCS operations, industrial and municipals, potentially generating over $1.4 billion in revenue. A flow-through model has been proposed to improve energy efficiency, reservoir management, and risk mitigation. This study advances to achieving net-zero targets and the United Nations Sustainable Development Goals on clean energy, climate action and sustainable communities.

Quantitative characterization and application of deep learning carbonate reservoir

Abstract Quantitative reservoir characterization is an important research task in carbonate reservoir development. At present, the comprehensive evaluation of drilling, logging, seismic, and productivity testing data is usually used, which requires a large number of test data and tedious manual data collation. Deep learning technology can independently learn complex reservoir characteristics, has a strong ability for high-dimensional data structure mining, and has a strong advantage in solving complex nonlinear reservoir description problems closely related to various geological characteristics. Therefore, this paper applies deep learning technology to reservoir characterization. First, a deep neural network model is constructed, and then seven characteristic parameters such as fracture density, fracture opening, fracture porosity, matrix porosity, total porosity, effective thickness, and specific oil production index are taken as input variables. After model training and verification, the effective permeability distribution map of the reservoir in the target area can be automatically generated. The results show that the deep learning method has strong adaptability and practicability for the quantitative characterization of complex reservoirs, and provides a new way of thinking for the quantitative characterization of reservoirs.

Characteristics and Genesis of Carbonate Weathering Crust Reservoirs: A Case from the Ma5Member of Ordovician in Gaoqiao Area, Ordos Basin, China.

The hydrocarbon reserves in carbonate rocks account for about half of the global hydrocarbon reserves and are an important reservoir type. The Ordovician Majiagou Formation in the central Ordos Basin is a representative weathering crust reservoir. The Caledonian movement uplifted the stratum as a whole, and subsequently, 120 million years of exposed weathering, denudation, and leaching created this unique karst paleomorphology. Dolomite reservoirs have developed dissolved pores and microfractures, which are the best reserved spaces for natural gas and good hydrocarbon migration channels. This paper takes the Ma5Member (hereinafter referred to as Ma51+2) carbonate reservoir in Gaoqiao Gas Field as the research target, based on the core, thin section, cathodoluminescence, logging data, etc., and systematically study the effect of karstification on the reservoir and the genesis of the dolomite reservoir. The results show that the depositional period of the Ordovician Majiagou strata is a regression cycle and the depositional environment is a limited evaporative tidal flat. The reservoir lithology of Ma51+2 is mainly gypsiferous dolomite and micrite dolomite. The reservoir space types consist of intergranular pores, gypsum mold pore, intragranular dissolution pores, intercrystalline pores, and microfractures. The porosity has values from 0.3 to 11.2% (mostly less than 5.0%) with an average of 3.3%, and the permeability ranges from 0.003 to 13.2 mD (mostly less than 1 mD) with an average of 0.36 mD. Karstification is divided into three periods, including syngenetic karst, eogenetic karst, and burial karst. The sedimentary microfacies determine the material basis of the reservoir, and multistage karstification finally modifies the physical properties. By deeply exploring the formation mechanism and influencing factors of the carbonate reservoir in the Ordovician Majiagou Formation, it provides an important theoretical basis and practical guidance for oil and gas exploration and development. At the same time, it also has important reference value for understanding and predicting the development law and distribution characteristics of carbonate reservoirs under similar geological background.

Reservoir Characteristics of Marine–Continental Transitional Taiyuan Formation Shale and Its Influence on Methane Adsorption Capacity: A Case Study in Southern North China Basin

To further study the reservoir characteristics and adsorption capacity of the Taiyuan Formation shale in the South North China Basin (SNCB), the pore structure and adsorption capacity of shale are discussed using various analysis tests, including elemental geochemistry, organic geochemistry, mineral composition, low-temperature nitrogen adsorption (LTNA), and methane adsorption experiments. The results indicate that the Taiyuan Formation shale formed in a poor oxygen and anaerobic sedimentary environment in still water. The average value of total organic carbon (TOC) content is 2.37%. The organic matter type mainly consists of type III kerogen. The vitinite reflectance (Ro) ranges from 3.11% to 3.50%. The clay mineral content varies greatly, averaging at 40.7%, while the quartz content averages at 37.7%. The Taiyuan Formation shale mainly develops interparticle (InterP) pores, followed by organic pores, intraparticle (IntraP) pores, solution pores, and microfractures. BET specific surface area (SSA) is between 9.47 m2/g and 22.14 m2/g, while pore volume (PV) ranges from 0.0098 cm3/g to 0.022 cm3/g, indicating favorable conditions for shale gas storage. According to the results of the CH4 adsorption experiment, Langmuir volume from Taiyuan Formation shales exhibits 1.35~4.30 cm3/g, indicating excellent adsorption capacity. TOC content shows a positive correlation with both Langmuir volume and BET SSA from Taiyuan Formation shales, suggesting that TOC plays a crucial role in controlling microscopic pores and gas adsorption capacity. Organic matter enhances the shale adsorption capacity by providing abundant pore SSA. Due to formation compaction, the pore size of clay minerals decreases, leading to an increase in pore SSA, while kaolinite exhibits weak hydrophilic ability. Consequently, with the increase in clay minerals and kaolinite content, the shale adsorption capacity is enhanced to a certain extent. However, an increase in the carbonate mineral content may result in a decrease in the proportion of clay minerals, therefore reducing the CH4 adsorption capacity of shale.

Study on the fluidity of the pore-fracture binary system in a tight sandstone reservoir-NMR

Fluid movability in tight sands may not be accurately characterized by pore size-based classification methods solely because of the complex pore structure and heterogeneity in pore size. In this study, on the basis of casting thin slices and scanning electron microscope observation, pore structure was analyzed using mercury injection, NMR, and micron CT to classify and evaluate the tight oil reservoir. The experiment suggest that the quality of tight reservoir is determined by its pore structure, particularly the throat radius, with the microthroat being an essential factor in permeability. Uniquely, we divide the reservoir by Q-cluster with throat radius, displacement pressure, permeability and other parameters. Based on reservoir classification, this study proposed a method for studying the pore size classification of samples on the T2 spectrum by combining CT scanning with mercury intrusion and a NMR experiment. Pore fluids are generally classified into movable fluid and irreducible fluid by one or two NMR T2 cut-offs. The pore size distributions and capillarity boundaries are converted from T2 and mercury injection capillary pressure (MICP). We categorized pores into micropores (T2 < 1), macropores (T2 > 10, with T2 > 300 as fractures), and medium pores (the rest). The saturation of movable fluid and the percentage of micro-fractures can characterize the seepage characteristics of tight reservoirs, which is of great significance for the later periods of oilfield development.

Experimental Study on Gas Production Capacity of Composite Reservoir Depletion in Deep Carbonate Gas Reservoirs

Deep carbonate gas reservoirs exhibit diverse reservoir types and complex seepage patterns. To study the gas production capabilities of different composite reservoir types, we classified the reservoirs of the fourth member of the Dengying Formation in the Anyue Gas Field into high-quality reservoirs (HRs) and poor-quality reservoirs (PRs) based on high-pressure mercury injection (HPMI) experiment results. By varying the differential pressure of the depletion experiment and the connection method, as well as the permeability and water saturation of the composite core, the effects of well location deployment, permeability ratio of the high-quality reservoir and poor-quality reservoir (PRHPR), gas well production pressure difference (GWPPD), and water saturation on the depletion gas production characteristics of the composite reservoir were studied. The research results show that (1) deploying wells on HR enables high gas production rates and ultimate recovery rates; (2) only when the PRHPR falls within a reasonable range (21.88–43.19) can the “dynamic recharge” capability of PR and the high permeability of HR be coordinated to achieve high gas recovery rates; (3) a GWPPD of 3 MPa is optimal, resulting in fast gas production rates and high ultimate recovery rates for PR; (4) high water saturation (≥50%) leads to premature water breakthrough at the well bottom, decreased gas production rate, and sealing of HR and PR reserves by formation water. Combining experimental results with field production data is our next research focus. Our future research focus will be on integrating experimental results with field production data to provide solid theoretical support for the efficient development of this type of gas reservoir.

Multifractal characteristics on pore structure of Longmaxi shale using nuclear magnetic resonance (NMR)

The efficient exploration and extraction of shale gas is essential for China's energy structure as a replacement for natural gas. In this research, shale samples from the Longmaxi Formation in Changning, Sichuan Province were investigated for their pore structure. To achieve this, X-ray diffraction (XRD) and nuclear magnetic resonance (NMR) experiments were performed on the samples. Fractal theory was employed to characterize the pore structure and fractal features of the shale reservoirs. The fractal characteristics of reservoir rocks were correlated with physical parameters and mineral components to identify the controlling factors for the multifractal dimension. The results indicate the following: ① Quartz predominates in the mineral composition of shale in the study area, while clay minerals are the least abundant. ② The primary pore types observed in the samples are bound fluid pores, primarily controlled by mesopores (2 nm ≤ r ≤ 50 nm). ③ The calculated multifractal parameters show that the heterogeneous pore structure exhibits multifractal characteristics. ④ The low probability multifractal parameters Dmin-D0 and αmax-α0 were found to be negatively correlated with reservoir porosity, permeability, and clay mineral content, while the high probability multifractal parameters D0-Dmax and α0-αmin were found to be positively correlated with them. The comprehensive fractal characterization of reservoir rocks demonstrates the applicability of multifractal dimensions in characterizing the heterogeneity of shale reservoir pore structures, which holds potential promise for coal methane exploration.

Experimental Study on the Relationship Among Complex Resistivity, Water Saturation, and Salinity in the Jiaozuo Anthracite Reservoir.

In order to investigate the electrical response characteristics of anthracite coal reservoirs and their correlation with water saturation, salinity, and porosity, the complex resistivity of Zhaogu No. 2 mine anthracite coal was measured across a frequency range of 1 Hz to 100 kHz. The experimental findings indicate that as water saturation, salinity, and porosity increase, the amplitude of both the real and imaginary components of the complex resistance of the coal sample gradually decreases, leading to a decrease in the dispersion degree and an increase in the interface polarization frequency. By analyzing the experimental data and studying the polarization mechanism of coal in a sodium chloride solution, this study proposed an enhanced model that integrates the aspects of the Cole-Cole model and the Warburg model to overcome the limitations of the traditional first-order model, which can fit only single-peak curves. The second-order series Cole-Cole model not only delves into microscopic mechanisms underlying the low-frequency polarization effect of coal samples but also provides a highly accurate fit for complex resistivity dispersion curves under varying conditions. This research offers both an experimental foundation and a theoretical framework for leveraging the electrical properties of anthracite coal reservoirs in assessing the pore structure and permeability of coal seams.

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.

Stability of THAI in situ combustion process in reservoirs with layers of grading permeabilities and porosities: Detailed qualitative investigations

The world-wide reserves of heavy oil, tar sand, and bitumen, etc., outweigh those of conventional oil by a factor of 7/3. Given that the conventional reserves are being rapidly depleted, the need to develop and produce the unconventional resources has never been so critical. However, the proven most efficient and environmentally-friendly technology, namely the THAI process, still requires further study, and it has no documented design procedures that factor in the non-ideal geological features of heavy oil and bitumen reservoirs. Throughout the literature, there is little reported on the effects of gradations in reservoir petro-physical parameters on the performance of the THAI process. Consequently, this work reports the results of numerical simulations for four different kinds of reservoirs, each having progressive gradations in permeabilities and porosities. The major findings from this in depth study include.(i) In terms of the temperature distribution, regardless of the permeability and porosity gradations, the high temperature zone is always skewed towards the highest permeabilities and porosities zone. Furthermore, it is found that, in any model in which the shoes of the VI wells have no direct communication pathway with the highest permeabilities and porosities zones of the reservoirs, the high temperature zones occur in two chambers, otherwise, there is one high temperature zone.(ii) It is found that generally, the combustion front tends to be lopsided in favour of the most permeable and porous zone. In the case of a bottom-up progressive increase in permeabilities and porosities (model L1), the single combustion front has greatest advance horizontally at the top and axially in the middle of the reservoir, while in model L2 (the converse of model L1), the combustion fronts propagated in two chambers before the chambers overlapped in the toe region of the HP well where it advanced fastest. Therefore, the combustion zone in model L1 was far more stable than in model L2.(iii) It is found that the combustion fronts in model L3, with the lowest permeabilities and porosities at the centre in the longitudinal direction, propagated in two chambers that overlapped each other around the toe region of the HP well and advanced greatest in the HP well and on either lateral edge of the reservoir. In model L4, which has lateral gradation in permeabilities and porosities, however, the thinner edge of the wedge-shape combustion front had advanced fastest along the vertical mid-plane where the HP well was located. Thus, the combustion zone in model L3 was far more stable than that in model L4.(iv) It is found that in all the models except model L4, there exist rich oil saturation zones in the most permeable and porous regions located ahead of the mobile oil zone (MOZ) of each reservoir. These are formed due to restrictions in the pathways via which the mobilised oil can drain into the HP well. In model L4, the HP well is already in the most permeable zone and consequently, the fluids that favourably reach there are rapidly gravity-drained into the HP well.

Structural assessment and petrophysical evaluation of the pre-Cenomanian Nubian sandstone in the October Oil Field, central Gulf of Suez, Egypt

The low quality of the seismic resolution of the studied Cambrian Pre-Cenomanian formations, which rest directly on the basement in the October Field in the Gulf of Suez, requires study, and the structure pattern controlling these formations is uncertain. The poor quality of the seismic data resolution in the Gulf of Suez is due to the presence of thick sequences of evaporites represented by the South Gharib and Zeit formations. Therefore, the current study used seismic reflection data integrated with well-log data to define the structural-stratigraphic setting of the pre-Cretaceous Nubian reservoir sequence. The study aims at locating and delineating zones having excellent reservoir potential within the Nubian sequence horizons (Nubian Transition, main Nubian, Nubian marker-1, and Nubia marker-2, referred to as NT, MN, M1 and M2, respectively) through the integration of the 3D static modelling and the petrophysical parameters deduced from the well-log data processing. A detailed petrophysical analysis, based on the wireline logs of some wells, was performed to determine the lithological units using two types of cross plots (Neutron-Density and M-N plots), and the different petrophysical parameters that characterize the various Nubian horizons were also computed. 3D modelling was used to visualise the lateral and vertical changes of the reservoir characteristics. The seismic mapping reveals that the Nubian structure is controlled by an NW-SE trending (Clysmic trend) of an NE-plunging asymmetrical anticlinal feature unconformably resting on a basement horst. The main structure is affected by two major normal faults, which trend NW, andis cut by two smaller sub-parallel faults that disturb the core of the structure, which is unaffected by the easterly oriented faults of the Aqaba trend. The petrophysical analyses indicate that the Nubian sandstones have intervals of good reservoir quality, with a total net-pay thickness of about 500 m, net sand ratios (60–90 %), effective porosity (10–25 %), and hydrocarbon saturation (85%), which may encourage further drilling, especially in the southeast portion. The result of this study can be extended to the other Nubia sandstones resting on the basement complex in the Gulf of Suez.

Geological Controls on Reservoir Characteristics Influencing Shale Oil Occurrence in Lacustrine Mixed Fine-Grained Sediments of the Paleogene Funing Formation, Subei Basin

Geological Controls on Reservoir Characteristics Influencing Shale Oil Occurrence in Lacustrine Mixed Fine-Grained Sediments of the Paleogene Funing Formation, Subei Basin

Experimental study on reservoir particle migration induced by the injection-production process of underground gas storage

Multi cycle injection and production of underground gas storage (UGS) promote continuous changes in reservoir characteristics, to clarify the impact of different injection and production characteristics on the reservoir, taking carbonate rock fracture-pore type gas storage reservoirs as the research object, established a set of experimental methods based on production characteristics, quantitative analysis of reservoir damage caused by particle migration caused by increasing, decreasing, fluctuating, and reverse changes in production pressure difference. And the following research results are obtained. First, established experimental methods based on production characteristics, the production method includes increasing, decreasing, fluctuating, and reverse changes, realized experimental evaluation of simulating actual production full features. Second, there is a critical pressure difference in the migration of reservoir particles, the fluctuation of production pressure difference induce further migration of particles, resulting in natural unblocking or new blockage. Third, the change in the direction of production pressure difference can cause large particle sizes break into small particle sizes and migrate out of the pore throat, thus the permeability of the reservoir can be improved to a certain extent. It is concluded that controlling a certain production pressure difference during the injection and production process of UGS, not only meets production needs, but also alleviate the damage of injection production to reservoir permeability to a certain extent.

Limnological Characteristics and Relationships with Primary Productivity in Two High Andean Hydroelectric Reservoirs in Ecuador

Studies on limnology are essential to reservoir management; nevertheless, few are known about the limnological features of the Andean reservoirs in Ecuador. To overcome this limitation in the information, from December 2018 to December 2019, the limnological characteristics of El Labrado and Chanlud reservoirs in the Machángara river basin (Ecuador south) were examined. Using the light/dark bottles technique, the primary productivity (PP) of phytoplankton was studied in conjunction with (1) vertical profiles of oxygen concentrations, water temperature, nitrogen, phosphorus, alkalinity, and heterotrophic bacteria; (2) Secchi disk transparency; and (3) meteorological factors such as wind force, precipitation, and water level. Data indicate that both reservoirs are polymictic, with alkaline waters, low nutrients, and low PP rates. Despite this, a principal component analysis revealed that Chanlud exhibits higher nitrogen, alkalinity, heterotrophic bacteria, and PP values. In two approaches through multiple linear regression analysis, each per reservoir, the PP was explained mainly by water temperature, depth, light, heterotrophic bacteria, and meteorological parameters. The low concentrations of nutrients and the low residency time explain the low PP values. Likewise, the altitudinal factor (i.e., both reservoirs are 3400 m above sea level) and the low human perturbations in surrounding reservoir zones play a crucial role in explaining their poor PP. Notwithstanding the low metabolic rates, clear seasonal trends were observed in both reservoirs; the lowest PP rates occurred during the cold season. To our knowledge, this is the first limnological study of high Andean reservoirs in Ecuador. These findings should be part of Andean reservoir management protocols, contributing significantly to local conservation efforts. Additionally, they could be extrapolated as a frame of reference to similar eco-hydrological systems.

A Semianalytical Model for Advanced Description of Pressure Drop Funnel during Coalbed Methane Production.

Advanced description of pressure drop funnel is crucial in coalbed methane (CBM) production because of dewatering and depressurization methods. Improving the precision of the pressure drop funnel description facilitates obtaining the actual production status and productivity potential, both pivotal for responsible development plans. The study presents a semianalytical model that integrates pressure profiles and material balance equations, incorporating inner and outer boundary conditions, and dynamic reservoir characteristics. The pressure propagation characteristics in undersaturated coal reservoirs are described during the production life of CBM wells, and the model is validated using two wells with different production characteristics. The results indicate that the effect of water saturation on the expansion of the drainage radius surpasses that of the desorption radius, demonstrating a more precise prediction of the production boundary when dynamic water saturation is considered. Additionally, a rapid drop rate of bottomhole flowing pressure triggers simultaneous propagation of the drainage and desorption radii, resulting in a smaller production boundary and fewer well-controlled resources. Conversely, an appropriate production strategy results in a larger drainage radius and lower boundary pressure before massive gas desorption, thereby facilitating efficient propagation of the pressure drop funnel. Moreover, the pressure drop funnel characterized by the model can compute the dynamic CBM resources and recovery efficiency of a single well, providing a valuable basis for assessing productivity potential. In summary, this model offers a time-saving and practical tool for describing the dynamic pressure drop funnel in various CBM production stages and promoting efficient development for undersaturated CBM reservoirs.