How green can Amazon hydropower be? Net carbon emission from the largest hydropower plant in Amazonia

The current resurgence of hydropower expansion toward tropical areas has been largely based on run-of-the-river (ROR) dams, which are claimed to have lower environmental impacts due to their smaller reservoirs. The Belo Monte dam was built in Eastern Amazonia and holds the largest installed capacity among ROR power plants worldwide. Here, we show that postdamming greenhouse gas (GHG) emissions in the Belo Monte area are up to three times higher than preimpoundment fluxes and equivalent to about 15 to 55 kg CO2eq MWh−1. Since per-area emissions in Amazonian reservoirs are significantly higher than global averages, reducing flooded areas and prioritizing the power density of hydropower plants seem to effectively reduce their carbon footprints. Nevertheless, total GHG emissions are substantial even from this leading-edge ROR power plant. This argues in favor of avoiding hydropower expansion in Amazonia regardless of the reservoir type.

Machine Learning and Artificial Intelligence Provides Wolfcamp Completion Design Insight

The subject of this paper is the application of a unique machine learning approach to the evaluation of Wolfcamp B completions. A database consisting of Reservoir, Completion, Frac and Production information from 301 Multi-Fractured Horizontal Wolfcamp B Completions was assembled. These completions were from a 10-County area located in the Texas portion of the Permian Basin. Within this database there is a wide variation in completion design from many operators; lateral lengths ranging from a low of about 4,000 ft to a high of almost 15,000 ft, proppant intensities from 500 to 4,000 lb/ft and frac stage spacing from 59 to 769 ft. Two independent self-organizing data mappings (SOM) were performed; the first on completion and frac stage parameters, the second on reservoir and geology. Characteristics for wells assigned to each SOM bin were determined. These two mappings were then combined into a reservoir type vs completion type matrix. This type of approach is intended to remove systemactic errors in measuement, bias and inconsistencies in the database so that more realistic assessments about well performance can be made. Production for completion and reservoir type combinations were determined. As a final step, a feed forward neural network (ANN) model was developed from the mapped data. This model was used to estimate Wolfcamp B production and economics for completion and frac designs. In the performance of this project, it became apparent that the incorporation of reservoir data was essential to understanding the impact of completion and frac design on multi-fractured horizontal Wolfcamp B well production and economic performance. As we would expect, wells with the most permeability, higher pore pressure, effective porosity and lower water saturation have the greatest potential for hydrocarbon production. The most effective completion types have an optimum combination of proppant intensity, fluid intensity, treatment rate, frac stage spacing and perforation clustering. This paper will be of interest to anyone optimizing hydraulically fractured Wolfcamp B completion design or evaluating Permian Basin prospects. Also, of interest is the impact of reservoir and completion characteristics such as permeability, porosity, water saturation, pressure, offset well production, proppant intensity, fluid intensity, frac stage spacing and lateral length on well production and economics. The methodology used to evaluate the impact of reservoir and completion parameters for this Wolfcamp project is unique and novel. In addition, compared to other methodologies, it is low cost and fast. And though the focus of this paper is on the Wolfcamp B Formation in the Midland Basin, this approach and workflow can be applied to any formation in any Basin, provided sufficient data is available.

Evolution of Hydraulic Fracturing Operations & Technology Applications in India

From 2005 to 2020, the application of hydraulic fracturing technology in India has touched the length and breadth of the country in almost every basin and reservoir section. The variety of reservoirs and operating environment present in India governed this evolution over the past 15 years resulting in a different fit for purpose fracturing strategy for each basin varying from conventional single-stage fracturing (urban, desert & remote forested regions) to high volume multi-stage fracturing, deepwater frac-packs and offshore ultra-HPHT fracturing. The objective of this paper is to present the milestones along this evolution journey for hydraulic fracturing treatments in India from 2005 to 2020. This paper begins with a review of published industry literature from 2005 to 2020 categorized by reservoir type and the proven economical techno-operational fracturing strategy adopted during that period. The milestones are covered chronologically since the success or failure of technology application in one basin often influenced the adoption of novel hydraulic fracturing methods in other basins or by other operators during the initial years. The offshore evolution is branched between the west and the east coasts which have distinctly different journeys and challenges. The onshore evolution is split into 5 categories: Cambay onshoreBarmer Hills & Tight GasEast India CBM and shale gasAssam-Arakan BasinOnshore KG Basin Each of these regions is at different stages of evolution. The Barmer region is in the most advanced state of evolution with frac factories in place while the Assam-Arakan Basin is in a relatively nascent stage. Figure 1 presents estimated hydraulic stage count based on published literature underlining the exponential growth in hydraulic fracturing activity in India. This paper enlists the technical and operational challenges present in the onshore and offshore categories mentioned above along with the identified novel techno-operational strategies which have proven to be successful for various operators in India. A comparison is presented of the different timelines of the exploration-appraisal-development journey for each region based on the economic viability of fracturing solutions available today in the Industry. Lastly, specific non-technical challenges related to available infrastructure, logistics and social governance are discussed for each region. This paper concludes by identifying the next step-change in the evolution of hydraulic fracturing operations in India among the 5 categories. Each of Government, operators and service providers have important roles to play in expanding the adoption of this technology in India. These roles are discussed for each identified category with the perspective of continuing the country's journey towards energy security.

Effect of Clay Type on Emulsion Formation in Steam and Solvent Steamflooding

Summary The objectives of this study are to perform a fundamental analysis of the mutual interactions between crude oil components, water, hydrocarbon solvents, and clays, and to determine the optimum hydrocarbon solvent in solvent steamflooding for a particular reservoir type. The water/oil emulsion formation mechanism in the obtained oil for steam and solvent steamflooding processes has been studied via intermolecular associations between asphaltenes, water, and migrated clay particles. A series of 21 steam and solvent-steamflooding experiments has been conducted, first without any clays in the oil/sand packing, and then using two different clay types in the reservoir rock: Clay 1, which is kaolinite, and Clay 2, which is a mixture of kaolinite and illite. Paraffinic (propane, n-butane,n-pentane,n-hexane,n-heptane) and aromatic (toluene) solvents are coinjected with steam. Cumulative oil recovery is found to decrease in the following order: no clay, Clay 1, Clay 2. Based on the obtained produced oil analyses, Clay 1 and Clay 2 are found to have an affinity with the water and oil phases, respectively. Moreover, the biwettable nature of Clay 2 makes it dispersed in the oil phase toward the oil/water interface, stabilizing the water/oil emulsions. Paraffinic solvent n-hexane is found to be an optimum coinjector for solvent steamflooding in bitumen recovery.

In silico validation and fabrication of matrix diffusion based polymeric transdermal patches for repurposing gabapentin hydrochloride in neuropathic pain.

Background: Gabapentin (GBP) is an FDA approved drug for the treatment of partial and secondary generalized seizures, apart from being used for diabetic neuropathic pain. GBP displays highly intricate mechanism of action and its inhibitory response in elevated antagonism of NMDA (N-methyl-D-aspartate receptor) receptor and thus, can be repurposed for controlling neuropathic pain. Objective: Therefore, in the present study, we have selected hBCATc (human Pyridoxal 5’-phosphate dependent branched-chain aminotransferase cytosolic) gene that is highly expressed in neuropathic stressed conditions. Thereafter, have analyzed the GBP as its competitive inhibitor by homology modeling, molecular docking, also predicting its structural alerts and pharmacokinetic suitability through ADMET. However, GBP was found to be a potential drug in controlling neuropathic pain, still it has certain critical pharmacokinetics limitations therefore, the need for its targeted delivery was required and the same was attained by designing a GBP loaded trandermal patch (TDP). Methods: A suitable and equally efficacious GBP – TDP was developed by solvent evaporation method using PVP and HPMC in ratio of 2:1 as a polymer base for reservoir type of TDP. Also, PEG 400 was used as a plasticizer and PVA (4%) was taken for backing membrane preparation and then the optimized GBP-TDP was subjected for physical characterization, optimization and ex vivo release kinetics. Methods: A suitable and equally efficacious GBP – TDP was developed by solvent evaporation method using PVP and HPMC in ratio of 2:1 as a polymer base for reservoir type of TDP. Also, PEG 400 was used as a plasticizer and PVA (4%) was taken for backing membrane preparation and then the optimized GBP-TDP was subjected for physical characterization, optimization and ex vivo release kinetics. Results and conclusion: The results showed desired specifications with uneven and flaky surface appearance giving an avenue for controlled release of the drugs with 92.34 ± 1.43% of drug release in 10 h, further suggesting that GBP-TDP can be used as an effective tool against diabetic neuropathy pain.

Identification and logging evaluation of poor reservoirs in X Oilfield

The reservoirs of X Oilfield have the characteristics of fine lithology particles, strong pore structure heterogeneity, and high argillaceous reservoirs and thin layers are generally developed. Conventional logging interpretation cannot make a fine evaluation, which results in serious discrepancies between the interpretation results of some reservoirs and actual production performance, and reserves are underestimated. Improving poor reservoir identification and logging evaluation accuracy is of great significance to oilfield development. The flow zone indicator (FZI) is used to classify the reservoirs into three types, I, II, and III, and the classification results are combined to establish a reservoir type identification chart based on logging curves; the resolution matching method and the deconvolution method are used to improve the accuracy of thin-layer recognition. Finally, the logging interpretation model is reestablished. Logging evaluations were conducted on 20 wells in X oilfield, and Y core wells were used for verification. The application results show that this method can effectively improve the identification accuracy of thin oilfields and high argillaceous reservoirs; the results of fine logging interpretation of poor reservoirs are consistent with core analysis conclusions and actual production conditions, which are typical of the successful application of poor reservoir technology.

Architectural characterization of Ordovician fault-controlled paleokarst carbonate reservoirs, Tahe oilfield, China

Fault-controlled karst carbonate reservoirs are one of the most important reservoir types in the Tahe oilfield of the Tarim Basin. These reservoirs have a large oil reserve and belong to a strongly reconstructed reservoir type with a highly heterogeneous distribution of pores and fractures. This study characterizes a fault-controlled karst reservoir by using integrated methods, including outcrops, well logging, structure interpretation, seismic inversion, and statistical geomodeling. We have established a fault-/fracture-controlling karstic geologic model and classified the internal architectural elements so that we adopted an origin-controlled hierarchical geomodeling strategy based on the fault-controlling characteristics. The results determined that large strike-slip faults provide an important tectonic framework and that its derived fractures act as important channels and spaces for dissolution. Flower structure fault zones and the associated fractures are the main range of karst development, within which a high stress is concentrated during the strike-slip shear process with a high-density fracture development. This is the highly developed karst reservoir, which mainly is concentrated along large faults. The coexistence of fractures and karst dissolution has resulted in a complicated reservoir architecture (karst architecture), which can be classified into four types: (1) large caverns, (2) small caverns and vugs, (3) fractured zones, and (4) matrix (tight limestone). Controlled by the degree of dissolution, the karst architecture is quite different from the sedimentary facies. Large caverns are formed under the strongest degree of dissolution and are the most favorable reservoir type. Small caves and vugs are created under relatively strong dissolution; they are distributed outside large caves and also can act as favorable reservoirs. The fractured zones are not necessarily affected by strong dissolution but have high conductivity and act as important channels for fluid movement. The carbonate matrix is less reconstructed. The architecture development model of the fault-controlled karst carbonate reservoir presented a tree system, within which the karst reservoir caves are connected by the fractures and faults similar to fruits and trunks. The new geomodeling method revealed the constraining characteristics of faults, seismic attributes, and hierarchical architectural elements. Furthermore, we also have built a 3D model of the Tuoputai unit in the Tahe oilfield to show the robustness of this workflow. This research enables us to better understand the structure of fault-controlled karst reservoirs, and it could provide a specified characterization approach that is considered to be theoretically and practically useful.

Liquid and Gas Corrected Permeability Correlation for Heterogeneous Carbonate Reservoir Rocks

Permeability is considered as an efficient parameter for reservoir modelling and simulation in different types of rocks. The performance of a dynamic model for estimation of reservoir properties based on liquid permeability has been widely established for reservoir rocks. Consequently, the validated module can be applied into another reservoir type with examination of the validity and applicability of the outcomes. In this study the heterogeneous carbonate reservoir rock samples of the Tertiary Baba Formation have been collected to create a new module for estimation of the brine permeability from the corrected gas permeability. In addition, three previously published equations of different reservoir rock types were evaluated using the heterogenous carbonate samples. The porosity and permeability relationships, permeability distribution, pore system and rock microstructures are the dominant factors that influenced on the limitation of these modules for calculating absolute liquid permeability from the klinkenberg-corrected permeability. The most accurate equation throughout the selected samples in this study was the heterogenous module and the lowest quality permeability estimation was derived from the sandstone module.

Successful Geological Strategy for Setting Intermediate Casing Prior Approaching Kujung Carbonate in Jambaran Field, Cepu Block

Jambaran Field was discovered in 2001 by J-1ST1 exploration well. The discovery well encountered steep-flanked carbonate build-up structure (Kujung Fm) that contain thick gas column and thin oil rim. To date six more wells have been drilled to unravel the geometry of the carbonate build up reservoir type. The carbonate build up which is up to 10 km length and 1 km width was deposited during Oligo-Early Miocene and sealed cap by very thick Tuban shale. This stratigraphic configuration has caused several drilling risks. First, there is a huge drop in pore pressure value between Tuban Shale and Kujung Carbonate; of up to 12.6 ppg in Tuban Shale and 8.1-11 ppg in Kujung Carbonate. Second, shale instability commonly happened during drilling Tuban shale. Third, total loss circulation, which can lead to H2S gas kick, potentially happened once penetrating Kujung Carbonate. To reduce those drilling risks, the casing ought to cover as much as Tuban Shale and as close as possible to Kujung Carbonate. During the exploration wells drilling, conventional methods such as; cutting observation, wetness-balance gas ratio, calcimetry, and mud losses have been applied to hunt the casing point as close as possible to Kujung Carbonate. Those conventional methods were successful in several well but also failed in the others. There are many other sophisticated tools developed by Service Company to serve the purpose of set casing, such as resistivity at bit. However, in our ongoing development wells drilling campaign, we utilized the combination of those conventional methods successfully to set 9-5/8” casing point as close as possible without entering Kujung Carbonate.