Oil transfer pump is the key dynamic equipment in the process of oil and gas gathering and transportation, and its working reliability directly affects the safety of oil and gas storage and transportation. Intelligent diagnosis is a key technical method to reduce failure rate of oil transfer pump, ensure the safety of gathering and transportation process, and avoid major safety accidents caused by oil transfer pump failure. Various oil transfer pumps have been emerged in recent decades, and the common fault types and characteristics of oil transfer pump have been brought out in the review. This article highlights on the research of the fault signal and processing methods of oil transfer pump. Firstly, the fault signal of the oil transfer pump is discussed and the advantages and disadvantages of different signal extraction are analyzed. Secondly, the intelligent diagnosis method of oil transfer pump and the shortcomings of the existing methods are pointed out. Finally, the conclusions are given and the future development perspectives of oil transfer pumps are suggested. The main contribution of this review is to give a syn-thetic understanding on oil transfer pumps.

The Oligo-Miocene Asmari Formation is one of the most important hydrocarbon reservoirs in the Middle East. The oilfield under study is one of the largest oilfields in the Zagros basin with the Asmari Formation being the major reservoir rock. In this study, petrographic analyses, petrophysical data and neural network clustering techniques were used for identifying rock types in the Asmari reservoir. Facies analysis of the Asmari Formation in the study area has resulted in the definition of 1 clastic lithofacies and 14 carbonate microfacies types. Using petrophysical logs from 43 wells and their correlation with capillary pressure (P_c) curves, led to the recognition of 7 electrofacies (EF1-EF7). Microscopic evidence of Electrofacies group C1 and S1 show that the sedimentary facies of these electrofacies are most commonly found in restricted and shoal facies belts zone. Also, petrographic studies show that the sedimentary facies of C2, C3, C4, S2 and S3 were formed in the open marine, Lagoon, and Tidal flat facies belt zone of homoclinal ramp sedimentary environment during the Oligo-Miocene based on relative sea level changes respectively. The link between electrofacies and geological data indicated that both sedimentary and diagenetic processes controlled the reservoir quality of the Asmari Formation. Porosity, permeability and water saturation were used to estimate the reservoir quality of each electrofacies. EFs 1 and 2 with high porosity and permeability, low water saturation is considered as the best reservoir with regard to sedimentary textures (dolowackestone and dolograinstone) and the effect of diagenetic processes such as dolomitization processes. Vuggy, growth framework and interparticle porosities are major in EF-2, while the intercrystalline porosity is the major type in EF-1. EFs 3 and 4 show low values of porosity, permeability and high percentage of water saturations, which characterizes them as poor reservoir rocks. Finally, EF-5 is the only electrofacies in the siliciclastic parts of the Asmari reservoir, which is composed of rounded and well-sorted quartz grains that are slightly cemented. In sandstone electrofacies, electrofacies EF-5 (S1), is the best type of sandstone reservoir rock and to move towards electrofacies EF-7 (S3), will reduce reservoir quality. In carbonate electrofacies, also, electrofacies no 1, the best type of carbonate reservoir rock can be observed and move towards electrofacie number 4, lower quality of reservoir rocks is seen.

Derivative/volatility well-log attributes from very few commonly recorded well logs can assist in the prediction of total organic carbon (TOC) in shales and tight formations. This is of value where only limited suites of well logs are recorded, and few laboratory measurements of TOC are conducted on rock samples. Data from two Lower-Barnett-Shale (LBS) wells (USA), including well logs and core analysis is considered. It demonstrates how well-log attributes can be exploited with machine learning (ML) to generate accurate TOC predictions. Six attributes are calculated for gamma-ray (GR), bulk-density (PB) and compressional-sonic (DT) logs. Used in combination with just one of those recorded logs, those attributes deliver more accurate TOC predictions with ML models than using all three recorded logs. When used in combination with two or three of the recorded logs, the attributes generate TOC prediction accuracy comparable with ML models using five recorded well logs. Multi-K-fold-cross-validation analysis reveals that the K-nearest-neighbour algorithm yields the most accurate TOC predictions for the LBS dataset. The extreme-gradient-boosting (XGB) algorithm also performs well. XGB is able to provide information about the relative importance of each well-log attribute used as an input variable. This facilitates feature selection making it possible to reduce the number of attributes required to generate accurate TOC predictions from just two or three recorded well logs.

The dolostones and dolomitic limestones of the lower Cretaceous Judea formation are a key target of hydrocarbons in most of the Euphrates Graben fields. Core materials investigation, thin sections petrographically examinations, and petrophysical evaluations were obtained to determine enhancement of the porosity through dolomitization. Results showed that the lagoon-shallow marine carbonates of the Judea formation are subdivided into two main zones; the upper “limestone zone” is micritic limestones dominated with no reservoir potential, and the lower “dolomite zone” is dolomitic limestones and dolostones dominated with good to very good reservoir potential. Dolomitization of the mudstones and wackestones of the micritic limestones resulted in formation of microcrystalline dolomicrite and early fabric destructive dolomites. Conversely, dolomitization of the packstones and grainstones resulted in formation of the fabric destructive and saddle dolomites. Based on petrography data, dolomitization of the “limestone zone” is interpreted by the seawater dolomitization mechanism at low-temperatures, while dolomitization of the “dolomite zone” is interpreted by the burial dolomitization mechanism under high temperature and pressure conditions. The “limestone zone” is characterized by the poorest reservoir quality, while the “dolomite zone” is characterized by the best reservoir quality. The seawater dolomitization did not significantly enhance the porosity, while the burial dolomitization contributes to enhancing the preserved secondary porosity. Stylolites microfractures and dissolution seams associated with dolomitization played as major factors in porosity enhancement of the dolostones and dolomitic limestones and serving as pathways for hydrocarbon migration. Dissolution processes increased the porosity and more permeability unless they are filled with the precipitated dolomite and/or calcite. Calcification had significant effects on the porosity by blocking the cavities and channels and decreased the effective pore volume.

Colloidal gas aphron (CGA) based fluid has become very popular in drilling in the last two decades, as it reduces formation damages significantly. In this study, sugarcane molasses (Mls) was used for the first time as a polymer in CGA-based to investigate its ability to improve the role of aphronized fluid as a drilling fluid. The results showed that increasing the concentration of Mls to 12% (v/v) in CGA-based fluid reduces the drainage rate and increases half-life to 10.6 min, resulting in enhanced stability of the aphronized fluid. Also, because of increasing Mls concentration from 1% to 12% (v/v), the yield and the initial gas hold-up decrease to 74% and 299.4 mL, respectively, indicating that the presence of Mls allows less air into the aphron system. Although the rheological properties were improved in this study, the gel strength did not change considerably. Furthermore, the results showed that by increasing the concentration of Mls, the average size of the bubbles decreases, and the particle-size distribution becomes more uniform. Finally, the API filtration test revealed that the higher the Mls concentration in the aphronized fluid, the lower the fluid loss, and at the Mls concentration of 12% (v/v), the fluid loss was estimated at 19.54 mL. A natural polysaccharide with high molecular weight, Mls can be used as a polymer in CGA-based fluid and, thus, improve its performance.

Improper drilling parameters may cause severe vibration of drill string which leads to reduce the rate of penetration and drilling tool premature failure accidents in the drilling process of ultra-deep well. The study on dynamic characteristics of drill string plays an important role in increasing the safety of drilling tool and optimizing the drilling parameters. Considering the influences of real borehole trajectory, interaction between bit and formation, contact between drill string and borehole wall, stiction of drilling fluid and other factors, a comprehensive drill string dynamic model was established to simulate the changes of wellhead hook load, torque, equivalent stress of drill string and BHA (bottom-hole assembly) section acceleration and motion trajectory with time at different WOBs (weights on bit) and rotary speeds. The safety factor and overpull margin of wellhead drill string were calculated and the strength of drilling tool in ultra-deep well was checked using the fourth strength theory. The analysis results show that, in the drilling process of ultra-deep well, the transverse motion amplitude of the drill string near the wellhead is relatively small and vibration of drill string mainly occurs in the lower well section. As the rotary speed increases, the number of collision between lower drilling tool and borehole wall increases, wellhead transverse stress increases, change in torque is not large and change in wellhead equivalent stress is relatively small. As the WOB increases, wellhead torque will increase, axial load and equivalent stress will decrease and vibration acceleration of BHA will increase sharply. Wellhead overpull margin and safety factor will decrease with the increase of rotary speed and increase with the increase of WOB. Wellhead safety factor of S135 drilling tool in an Φ190.5 mm ultra-deep well on the south margins of Junggar basin changes around 1.8. The drilling tool is safe and has relatively sufficient ability to deal with the downhole accidents if a large size high steel grade drill string (Φ139.7 mm S135) is used. However, in view of BHA safety, neither rotary speed shall be too high nor WOB shall be too large.

The polymer solution flow in porous media is a central research topic related to hydraulic fracturing measures, formation damage and fracture propagation. Influenced by molecular weights and concentrations, various flow patterns of polymer in pores are presented, resulting in different filtration loss. In this work, the effectiveness of various polymer solutions for filtration loss was assessed by utilizing the core flooding experiment firstly. The result shows that lesser filtration loss normally is inextricably linked to solutions with high molecular weight and concentration. Subsequently, the flow behaviors of polymer solutions investigated by designed micro pore-throat structure and micro-particle image velocimetry (μ-PIV) further confirmed the above result. It was found that the central convergent flow pattern benefiting from higher viscous force loss and less filtration loss was observed at high flow rates (0.5 mL/h), and higher molecular weight and concentration were more prone to convergent flow patterns. The viscosity force loss increases by about 4 times varying the molecular weight of polymer from 5 × 10⁶ to 18 × 10⁶ g/mol or the concentration from 0.05 to 0.3%. It interprets higher molecular weight and concentration in core studies and field observations with decreased filtration loss of HPAM. This work provides a theoretical foundation for the application of fracturing fluids as well as fresh perspectives on how to access the filtration loss of fracturing fluids.

Primary oil recovery is the first stage of hydrocarbon production in which a reservoir uses its natural energy to force hydrocarbon to its wellbore. Secondary oil recovery comes to play when hydrocarbons can no longer be further produced by natural means. The purpose of secondary recovery is to maintain reservoir pressure so as to displace hydrocarbons toward the wellbore. Both primary and secondary recovery processes cannot displace more than 50% of the available hydrocarbons in a reservoir. The remaining hydrocarbons are further recovered through Tertiary/Enhanced Oil Recovery techniques. According to literature, microbial enhanced oil recovery has been identified as a tertiary method used to improve the efficiency of hydrocarbon production from reservoirs. Microbial enhanced oil recovery is a feasible reservoir technology, which has not been widely used in the oil and gas industry owing to the attainment of the requisite reservoir conditions such as temperature within which microbes can thrive. Literature has shown that thermotolerant microbes can withstand optimum temperatures of 50-90°C, while deep and ultra-deep hydrocarbon reservoir temperatures are often above 100°C. This study identifies some isolated thermotolerant microbes from a sandstone reservoir that can withstand temperatures as high as 110°C via conventional methods and molecular analysis. The identified thermotolerant petroleum microbes: Bacillus amyloliquefaciens (A) and Bacillus nealsonii (B) were used to enhance oil recovery from a reservoir. The results showed that the microbial species A and B at a confined pressure of 3.0 MPa and temperature of 27°C, gave 46.4% and 48.6% oil recoveries, respectively, which is comparably higher than the value (26.9%) obtained for the water flooded samples. At temperatures of 80, 90, 100, 110 and 120°C, the oil recovery results show that the recovery factor (55.2%-64.1%) of species B were higher compared to the range (46.7-57.5%) recorded for species A. At the onset of the core flooding experiments, there was an initial increment in oil recovery factor as the temperature increased from 80 to 110°C, whereas, it remained constant within 110-120°C. This trend coincides with the drop in the thermal resistance exhibited by the microbes when exposed to such conditions. The cumulative oil production from the commercial Eclipse simulation closely matched those of the experiment results, whereas, the slight difference can be attributed to the adjustment of the simulation input parameters. The experimental results show that species B can be used to enhance oil recovery at reservoir temperature conditions above 100°C.

As a potential resource for emerging clean energy with abundant reserves, coalbed methane (CBM) has risen rapidly in recent years, and the construction of rational and economical CBM gathering system plays a vital role in the development of the oil and gas industry. At present, there is no literature that considers the optimization of the multi-gathering mode of coalbed methane pipe network system. Due to the complexity and high investment, this paper establishes a unified mixed-integer nonlinear programming model to determine the gathering modes (including liquified natural gas, compressed natural gas, and gas gathering station) of gathering system to reduce the cost of coalbed methane collection and export. The objective function is the maximization of total profit during the period of the whole project, and such constraints, like network structure, facility number, location, node flow balance, capacity and variable value, are taken into consideration. The solution strategy and heuristic algorithm is proposed and verified by the field data from Shanxi province (China). The results show that the model can solve the problem for optimization design of the surface system in complicated CBM fields.

To explore the damage behavior of O-ring in acid environment, a high-temperature and high-pressure (HTHP) autoclave was used to simulate the service environment of O-ring, and then 168h corrosion test of hydrogenated nitrile butadiene rubber (HNBR) and fluororubber (FM) O-rings were carried out. The corrosion damage behaviors of two kinds of rubber O-rings in the acidizing fluid were studied through determining their tensile strength, elongation at break, hardness, permanent compressive deformation, tensile fracture morphology and sealing property. The results showed that the cross-sectional area and the compression permanent deformation increased, the tensile strength and hardness decreased when the HNBR and FM O-rings under the free state were subjected to acid corrosion. The elongation at break of HNBR decreased, and that of FM rubber increased greatly. Similar with free state, the HNBR and FM O-rings under sealed state also presented the same variation trend. The decrease in the reliability of the O-rings under the sealed state was less significant than that in the free state. In the test, tensile fractures were mostly brittle fractures, HNBR and FM O-rings had obvious corrosion damages such as deformation and swelling. The results could provide a technical basis for the selection of sealing materials, tool optimization design, and construction work in oil and gas fields.

Surfactant foam stability gets a lot of interest while posing a significant obstacle to many industrial operations. One of the viable solutions for addressing gas mobility concerns and boosting reservoir fluid sweep efficiency during solvent-based enhanced heavy oil recovery processes is foam formation. The synergistic effect of nanoparticles and surfactants in a porous reservoir media can help create a more durable and sturdier foam. This study aims to see how well a combination of the nanoparticles (NPs) and surfactant can generate foam for controlling gas mobility and improving oil recovery. This research looked at the effects of silicon and aluminum oxide nanoparticles on the bulk and dynamic stability of sodium dodecyl surfactant (SDS)-foam in the presence and absence of oil. Normalized foam height, liquid drainage, half-decay life, nanoparticle deposition, and bubble size distribution of the generated foams with time were used to assess static foam stability in the bulk phase, while dynamic stability was studied in the micromodel. To understand the processes of foam stabilization by nanoparticles, the microscopic images of foam and the shape of bubbles were examined. When nanoparticles were applied in foamability testing in bulk and dynamic phase, the foam generation and stability were improved by 23% and 17%, respectively. In comparison to surfactant alone, adding nanoparticles to surfactant solutions leads to a more significant pressure drop of 17.34 psi for SiO₂ and 14.86 psi for Al₂O₃ NPs and, as a result, a higher reduction in gas mobility which ultimately assists in enhancing oil recovery.

Triethylamine (TEA), 1, 4-dibromobutane (C₄H₈Br₂) and N, N-dimethylaminopropyl acrylamide (DMAPAA) were selected to synthesize a double quaternary ammonium cationic monomer (TDD). TDD, acrylamide (AM), 2-acrylamido-2-methylpropane sulfonic acid (AMPS) and acrylic acid (AA) were used to create a quadripolymer (PAAT) that was characterized by FT-IR and ¹H NMR. Following that, the basic performance of thickened acid was assessed. The results revealed that PAAT outperformed PAA (copolymerized by AM, AMPS and AA) in terms of acid solubility, thickening performance, temperature resistance and shear resistance. Furthermore, this crosslinked acid containing PAAT was subjected to a series of performance evaluations. The viscosity of the crosslinked acid could be kept at 67 mPa·s at 160°C after 90 min and the weight loss rate of crosslinked acid in acid-rock reaction at 60 min was 23%, indicating the temperature resistance and retarder performance of the crosslinked acid solution was significantly better than that of the thickening acid and the blank acid. A scanning electron microscopy experiment revealed that crosslinked acid has good corrosion ability and low damage to the reservoir. The above experimental results indicated that the thickener PAAT has a promising future application in acid fracturing of high-temperature and high-mineralization carbonate reservoirs.

Carbon dioxide (CO₂) capture, utilization, and storage (CCUS) is an important pathway for China to achieve its “2060 carbon neutrality” strategy. Geological sequestration of CO₂ in deep coals is one of the methods of CCUS. Here, the No. 3 anthracite in the Qinshui Basin was studied using the superposition of each CO₂ geological storage category to construct models for theoretical CO₂ geological storage capacity (TCGSC) assessment, and CO₂ adsorption capacity variation with depth. CO₂ geological storage potential of No. 3 anthracite coal was assessed by integrating the adsorption capacity with the static storage and dissolution capacities. The results show that (1) CO₂ adsorption capacities of XJ and SH coals initially increased with depth, peaked at 47.7 cm³/g and 41.5 cm³/g around 1000 m, and later decreased with depth. (2) four assessment areas and their geological model parameters were established based on CO₂ phase variation and spatial distribution of coal thickness, (3) the abundance of CO₂ geological storage capacity (ACGSC), which averages 40 cm³/g, shows an analogous circularity-sharp distribution, with the high abundance area influenced by depth and coal rank, and (4) the TCGSC and the effective CO₂ geological storage capacity (ECGSC) are 9.72 Gt and 6.54 Gt; the gas subcritical area accounted for 76.41% of the total TCGSC. Although adsorption-related storage capacity accounted for more than 90% of total TCGSC, its proportion, however, decreased with depth. Future CO₂-ECBM project should focus on high-rank coals in gas subcritical and gas-like supercritical areas. Such research will provide significant reference for assessment of CO₂ geological storage capacity in deep coals.

Consider a typical situation where an investor is considering acquiring an unexplored oilfield. The oilfield has undergone a preliminary geological and geophysical study in which pre-discovery data such as lithology, depth, depositional system, diagenetic overprint, structural compartmentalization, and trap type are available. In this situation, investors usually estimate production rates using a volumetric approach. A more accurate estimation of production rates can be obtained using analytical methods, which require additional data such as net pay, porosity, oil formation volume factor, permeability, viscosity, and pressure. We call these data post-discovery parameters because they are only available after discovery through exploration drilling. A data-driven approach to estimating post-discovery parameters of an unexplored oilfield is developed based on its pre-discovery data by learning from proven reservoir data. Using the Gaussian mixture model, and a data-driven reservoir typology based on the joint probability distribution of post-discovery parameters is established. We came up with 12 reservoir types. Subsequently, an artificial neural network classification model with the resilient backpropagation algorithm is used to find relationships between pre-discovery data and reservoir types. Based on k-fold cross-validation with k = 10, the accuracy of the classification model is stable with an average of 87.9%. With our approach, an investor considering acquiring an unexplored oilfield can classify the oilfield's reservoir into a particular type and estimate its post-discovery parameters' joint probability distribution. The investor can incorporate this information into a valuation model to calculate the production rates more accurately, estimate the oilfield's value and risk, and make an informed acquisition decision accordingly.

Steeply dipping prograding fan deltas possess high reservoir quality facies that could be excellent targets while exploring for hydrocarbons. Due to their complex stacking nature, and limited examples, delineating their architectural elements is still challenging. In this paper we mainly performed sedimentary facies analysis; applying various disciplines e.g. sequence stratigraphy, seismic stratigraphy, GR-log motifs, and seismic waveform segmentation; so as to adequately depict the reservoir heterogeneity and quality of the Paleozoic Nubia clastics in West Esh El Mallaha Concession (southwest Gulf of Suez rift). Organic maturity prediction, to confirm the hydrocarbon charging from source units to reservoir intervals, was also of most importance in this study. Accordingly, 1D basin model was established to define the past geologic events; subsidence, and thermal maturity; and their controls on sedimentary basin evolution and associated petroleum potential. We utilized several key-information scales; e.g. wireline logs, and seismic profiles. Linking different disciplines applied in this study points to a successful integrated reservoir characterization workflow capable of unfolding ancient environments and the associated hydrocarbon potential. The results show that Nubia Formation was built during the lowstand−transgressive phase of a 3rd order depositional sequence. It encompasses fluvio-lacustrine system with eight sedimentary facies associations; form source to sink. Fluvial channels and mouth bars, settled in subaerial and subaqueous settings respectively, represent the most significant reservoir facies in the area. Given best hydrocarbon-reservoir quality, the deltaic mouth bars ought to attract attention of further oilfield development plans and be considered while investigating similar settings.