Saudi Aramco (United States)

Familial persistent hyperinsulinemic hypoglycemia of infancy (PHHI), an autosomal recessive disorder characterized by unregulated insulin secretion, is linked to chromosome 11p14-15.1. The newly cloned high-affinity sulfonylurea receptor (SUR) gene, a regulator of insulin secretion, was mapped to 11p15.1 by means of fluorescence in situ hybridization. Two separate SUR gene splice site mutations, which segregated with disease phenotype, were identified in affected individuals from nine different families. Both mutations resulted in aberrant processing of the RNA sequence and disruption of the putative second nucleotide binding domain of the SUR protein. Abnormal insulin secretion in PHHI appears to be caused by mutations in the SUR gene.

Summary The formation of emulsions during oil production is a costly problem, both in terms of chemicals used and production lost. This paper discusses production and operational problems related to crude-oil emulsions and presents a review that will be useful for practicing engineers. The first part of this paper presents why emulsions form during oil production, the types of emulsions encountered, and new methods for characterizing them. Crude-oil emulsions are stabilized by rigid interfacial films that form a "skin" on water droplets and prevent the droplets from coalescing. The stability of these interfacial films, and hence, the stability of the emulsions, depends on a number of factors, including the heavy material in the crude oil (e.g., asphaltenes, resins, and waxes), solids (e.g., clays, scales, and corrosion products), temperature, droplet size and droplet-size distribution, pH, and oil and brine composition. The effects of these factors on emulsion stability are reviewed within this paper. The second part of this paper presents methods to tackle crude-oil emulsions. The focus is on the destabilization of emulsions and the demulsification process. Emulsions are destabilized by increasing temperature and residence time, removal of solids, and controlling emulsifiers. The mechanisms involved in demulsification (e.g., flocculation, aggregation, sedimentation, creaming, and coalescence) are discussed in terms of the stability of the interfacial films. The methods involved in demulsification—including thermal, mechanical, electrical, and chemical are also presented. Experience and economics determine which methods are used, and to what degree, for emulsion treatment. Finally, a section on field applications also is included that should be useful for the practicing engineer who deals with emulsions either regularly or on a limited basis. Herein the field-emulsion treatment program is discussed, and more importantly, methods to prevent emulsion problems are highlighted. Recommendations are made for reducing and optimizing demulsifier dosage and controlling emulsion problems.

Summary The impact of brine salinity and ion composition on oil recovery has been an area of research in recent years. Evidence from laboratory studies, supported by some field tests targeting mainly sandstones, has distinctly shown that injecting low-salinity water has a significant impact on oil recovery. Although the potential for carbonates has not been thoroughly investigated, some reported studies have excluded carbonates from this effect. The main objective of this paper is to investigate the potential of increased oil recovery by altering the salinity and ionic composition of the injection water for carbonate reservoirs, define the recovery mechanisms, and eventually transform the emerged trend to full-fledged reservoir technology. This paper presents the results of different laboratory studies to investigate the impact of salinity and ionic composition on oil/brine/rock interactions and draws conclusions on potential recovery mechanisms. Also, it provides a laboratory coreflooding study conducted using composite rock samples from a carbonate reservoir to investigate the impact of salinity and ionic composition on oil recovery. The experimental parameters and procedures were well designed to reflect the reservoir conditions and current field injection practices, including reservoir pressure, reservoir temperature, and salinity and ionic content of initial formation water and current types of injected water. The experimental results revealed that substantial tertiary oil recovery beyond conventional waterflooding can be achieved by altering the salinity and ionic content of field injected water. The new emerged trend is distinct from what has been addressed in previous reported studies on topics of low-salinity waterflooding for sandstones or seawater injection into high-temperature chalk reservoirs. On the subject of recovery mechanisms, the results showed that altering the salinity and ionic composition of the injected water has a significant impact on the wettability of the rock surface. Also, nuclear-magnetic-resonance (NMR) measurements indicated that dilution of seawater can cause a significant alteration in the surface relaxation of the carbonate rock and also can enhance connectivity among pore systems because of rock dissolution. The results, observations, and interpretations addressed in this study provided compelling evidence to suggest that the key mechanism for the emerged trend is wettability alteration.

ABSTRACT The Paleozoic section became prospective during the early 1970s when the enormous gas reserves in the Permian Khuff reservoirs were delineated in the Gulf and Zagros regions, and oil was discovered in Oman. Since then, frontier exploration has targeted the Paleozoic System throughout the Middle East, driven by various economic considerations. The Paleozoic sequences were essentially deposited in continental to deep marine clastic environments at the Gondwana continental margin. Carbonates only became dominant in the Late Permian. The sediments were deposited in arid to glacial settings, reflecting the drift of the region from equatorial to high southern latitudes and back. Following late Precambrian rifting that formed salt basins in Oman and the Arabian Gulf region, the Cambrian-Devonian sequences were deposited on a peneplained continental platform. The entire region was affected by the Hercynian Orogeny, which climaxed during the Carboniferous. The orogeny manifested itself in a change in basin geometry, inversion tectonics, regional uplift and tectonism along the Zagros fault zone. This deformation caused widespread erosion of the Devonian-Carboniferous and older sections, and was probably caused by collision along the northern margin of Gondwana. The Paleozoic tectonic super cycle ended with the onset of break-up tectonics in the Permian, and the deposition of Khuff carbonates over the newly formed eastern passive margin. A major Paleozoic petroleum system embraces reservoir seal pairs spanning the Silurian to Permian sequences. Hydrocarbons occur in a variety of traps, and are sourced by the Silurian ‘hot shale’. A second petroleum system occurs in areas charged from upper Precambrian source rocks in the salt basins. Hydrocarbon expulsion estimates, taking into account secondary migration losses, suggest that some one trillion barrels of oil equivalent (BOE) may have been trapped from the Silurian ‘hot shale’ alone. However, the long and complex hydrocarbon geological evolution of the basin, combined with low acoustic contrasts between target rock units, difficult surface conditions, tight reservoirs, and deep subsurface environments, posed significant challenges to exploration and development. The critical success factor is the continuous innovative effort of earth scientists and subsurface engineers to find integrated technology solutions, that will render the Paleozoic plays economically viable.

Abstract One of the most accepted geologic models is the relation between reflector curvature and the presence of open and closed fractures. Such fractures, as well as other small discontinuities, are relatively small and below the imaging range of conventional seismic data. Depending on the tectonic regime, structural geologists link open fractures to either Gaussian curvature or to curvature in the dip or strike directions. Reflector curvature is fractal in nature, with different tectonic and lithologic effects being illuminated at the 50-m and 1000-m scales. Until now, such curvature estimates have been limited to the analysis of picked horizons. We have developed what we feel to be the first volumetric spectral estimates of reflector curvature. We find that the most positive and negative curvatures are the most valuable in the conventional mapping of lineations — including faults, folds, and flexures. Curvature is mathematically independent of, and interpretatively complementary to, the well-established coherence geometric attribute. We find the long spectral wavelength curvature estimates to be of particular value in extracting subtle, broad features in the seismic data such as folds, flexures, collapse features, fault drags, and under- and overmigrated fault terminations. We illustrate the value of these spectral curvature estimates and compare them to other attributes through application to two land data sets — a salt dome from the onshore Louisiana Gulf Coast and a fractured/karsted data volume from Fort Worth basin of North Texas.

Summary This paper presents a new procedure to quantify communication between vertical wells in a reservoir on the basis of fluctuations in production and injection rates. The proposed procedure uses a nonlinear signal-processing model to provide information about preferential-transmissibility trends and the presence of flow barriers. Previous work used a steady-state (purely resistive) model of interwell communication. Data in that work often had to be filtered to account for compressibility effects and time lags. Even though it was often successful, the filtering required subjective judgment as to the goodness of the interpretation. This work uses a more complicated model that includes capacitance (compressibility) as well as resistive (transmissibility) effects. The procedure was tested on rates obtained from a numerical flow simulator. It was then applied to a short-time-scale data set from an Argentinean field and a large-scale data set from a North Sea field. The simulation results and field applications show that the connectivity between wells is described by model coefficients (weights) that are consistent with known geology, the distance between wells, and their relative positions. The developed procedure provides parameters that explicitly indicate the attenuation and time lag between injector and producer pairs in a field without filtering. The new procedure provides a better insight into the well-to-well connectivities for both fields than the purely resistive model. The new procedure has several additional advantages. Itcan be applied to fields in which wells are shut in frequently or for long periods of time.allows for application to fields in which the rates have a remnant of primary production.has the capability to incorporate bottomhole-pressure (BHP) data (if available) to enhance the investigation about well connectivity. Introduction Production and injection rates are the most abundant data available in any injection project. Valuable and useful information about interwell connectivity can be obtained from the analysis of these data. The information may be used to optimize subsequent oil recovery by changing injection patterns, assignment of priorities in operations, recompletion of wells, and infill drilling. A variety of methods have been used to compare the rate performance of a producing well with that of the surrounding injectors. Heffer et al. (1997) used Spearman rank correlations to relate injector/producer pairs and associated these relations with geomechanics. Refunjol (1996), who also used Spearman analysis to determine preferential-flow trends in a reservoir, related injection wells to their adjacent producers and used time lags to find an extreme coefficient value. De Sant'Anna Pizarro (1998) validated the Spearman rank technique with numerical simulation and pointed out its advantages and limitations. Panda and Chopra (1998) used artificial neural networks to determine the interaction between injector/producer pairs. Soeriawinata and Kelkar (1999), who also used Spearman rank analysis, suggested a statistical approach to relate injection wells and their adjacent producing wells. They applied superposition to introduce concepts of constructive and destructive interference. See also the works of Araque-Martinez (1993) and Barros-Griffiths (1998). Albertoni and Lake (2003) estimated interwell connectivity on the basis of a linear model with coefficients estimated by multiple linear regression (MLR). The linear-model coefficients, or weights, quantitatively indicate the communication between a producer and the injectors in a waterflood. Filters were adopted to account for the time lag between producer and injector. In this work, as in Albertoni and Lake (2003), the reservoir is viewed as a system that converts an input signal (injection) into an output signal (production). However, we use a more complete model that includes capacitance (compressibility) as well as resistive (transmissibility) effects. For each injector/producer pair, two coefficients are determined; one parameter (the weight) quantifies the connectivity, and another (the time constant) quantifies the degree of fluid storage between the wells. This work shows that the new model better captures the true attenuation and time lag between injector and producer pairs. The new procedure resolves several limitations of the previous methods and extends the applications to a wide range of real cases. It can be applied to fields in which wells are shut in frequently or for long periods of time, it allows for application to fields in which the rates have a remnant of primary production, and it has the capability to use BHP data (if available) to enhance the investigation of the well's connectivity.

The main function of traditional proppants is to provide and maintain conductive fractures during well production where proppants should meet closure stress requirement and show resistance to diagenesis under downhole conditions. Many different proppants have been developed in the oil & gas industry, with various types, sizes, shapes, and applications. While most proppants are simply made of silica or ceramics, advanced proppants like ultra-lightweight proppant is also desirable since it reduces proppant settling and requires low viscosity fluids to transport. Additionally, multifunctional proppants may be used as a crude way to detect hydraulic fracture geometry or as matrices to slowly release downhole chemical additives, besides their basic function of maintaining conductive hydraulic fractures. Different from the conventional approach where proppant is pumped downhole in frac fluids, a revolutionary way to generate in-situ spherical proppants has been reported recently. This paper presents a comprehensive review of over 100 papers published in the past several decades on the subject. The objectives of this review study are to provide an overview of current proppant technologies, including different types, compositions, and shapes of proppants, new technologies to pump and organize proppants downhole such as channel fracturing, and also in-situ proppant generation. Finally, the paper sheds light on the current challenges and emphasizes needs for new proppant development for unconventional resources.

The possibility to fulfill the increasing market demand and producers' needs in processing straightforwardly crude oil, a cheap and universally available feedstock, to produce petrochemicals appears to be a very attractive strategy.

Abstract Rational design of highly efficient bifunctional electrocatalysts based on 3D transition‐metal‐based materials for oxygen evolution reaction (OER) and hydrogen evolution reaction (HER) is of great importance for sustainable energy conversion processes. Herein, a novel strategy involving outer and inner structural engineering is developed for superior water splitting via in situ vertical growth of 2D amorphous FePO 4 nanosheets on Ni foam (Am FePO 4 /NF). Careful experiments and density functional theory calculations show that the inner and outer structural engineering contributing to the synergistic effects of 2D morphology, amorphous structure, conductive substrate, and Ni−Fe mixed phosphate lead to superior electrocatalytic activity toward OER and HER. Furthermore, a two‐electrode electrolyzer assembled using Am FePO 4 /NF as an electrocatalyst at both electrodes gives current densities of 10 and 100 mA cm −2 at potentials of 1.54 and 1.72 V, respectively, which is comparable to the best bifunctional electrocatalyst reported in the literature. The strategies, introduced in the present work, may open new opportunities for the rational design of other 3D transition‐metal‐based electrocatalyst through an outer and inner structural control to strengthen the electrocatalytic performance.

Mapping fault planes using seismic images is a crucial and time-consuming step in hydrocarbon prospecting. Conventionally, this requires significant manual efforts that normally go through several iterations to optimize how the different fault planes connect with each other. Many techniques have been developed to automate this process, such as seismic coherence estimation, edge detection, and ant-tracking, to name a few. However, these techniques do not take advantage of the valuable experience accumulated by the interpreters. We have developed a method that uses the convolutional neural network (CNN) to automatically detect and map fault zones using 3D seismic images in a similar fashion to the way done by interpreters. This new technique is implemented in two steps: training and prediction. In the training step, a CNN model is trained with annotated seismic image cubes of field data, where every point in the seismic image is labeled as fault or nonfault. In the prediction step, the trained model is applied to compute fault probabilities at every location in other seismic image cubes. Unlike reported methods in the literature, our technique does not require precomputed attributes to predict the faults. We verified our approach on the synthetic and field data sets. We clearly determined that the CNN-computed fault probability outperformed that obtained using the coherence technique in terms of exhibiting clearer discontinuities. With the capability of emulating human experience and evolving through training using new field data sets, deep-learning tools manifest huge potential in automating and advancing seismic fault mapping.

Abstract The Zagros Basin is broadly defined as the palaeodepositional wedge of sediments along the present belt of the Zagros Mountains. A series of ten regional isopach maps trace the development of a portion of this basin from Permian to Recent. From the Permian to the middle Cretaceous the area occupied a position along the stable northeastern Atlantic-type shelf margin of the Afro-Arabian continent, bounded by a rift zone that evolved into a southern Tethys ocean. Late Cretaceous to Recent subsidence patterns are influenced by plate margin tectonics, obduction, and eventual continental collision along the Zagros Suture as this ocean closed. The late Alpine Zagros folding and faulting took place from the Miocene onwards.

Abstract The impact of brine salinity and ion composition on oil recovery has been an area of research in recent years. Evidence from laboratory studies supported by some field tests targeting mainly sandstones, has distinctly shown that injecting low salinity water has a significant impact on oil recovery. Although, the potential for carbonates has not been thoroughly investigated, some reported studies have excluded carbonates from this effect. The main objective of this paper is to investigate the potential of increased oil recovery by altering the salinity and ion composition of the injection water for carbonate reservoirs, define the recovery mechanisms, and eventually transform the emerged trend to full-fledged reservoir technology. This paper presents the results of a laboratory coreflooding study conducted using composite rock samples from a carbonate reservoir to investigate the impact of salinity and ionic composition on oil/brine/rock interactions, and eventually on oil recovery. The experimental parameters and procedures were well designed to reflect the reservoir conditions and current field injection practices, including reservoir pressure, reservoir temperature, salinity and ionic content of initial formation water and current types of injected water. Also, this study provides detailed discussion and interpretation for potential mechanisms. The experimental results revealed that substantial tertiary oil recovery beyond conventional waterflooding can be achieved by altering the salinity and ionic content of field injected water. The new emerged trend is distinct from what has been addressed in previous reported studies on topics of low salinity waterflooding for sandstones, or seawater injection into high temperature chalk reservoirs. On the subject of recovery mechanisms, the results showed that altering the salinity and ionic composition of the injected water has a significant impact on the wettability of the rock surface. This was also confirmed by nuclear magnetic resonance (NMR) measurements. The results, observations, and interpretations addressed in this study provided compelling evidence to suggest that the key mechanism for the emerged trend is wettability alteration.

A family of deep eutectic solvents with high gravimetric capacities is reported for CO₂ capture.

Multiphase flows in porous media are important in many natural and industrial processes. Pore-scale models for multiphase flows have seen rapid development in recent years and are becoming increasingly useful as predictive tools in both academic and industrial applications. However, quantitative comparisons between different pore-scale models, and between these models and experimental data, are lacking. Here, we perform an objective comparison of a variety of state-of-the-art pore-scale models, including lattice Boltzmann, stochastic rotation dynamics, volume-of-fluid, level-set, phase-field, and pore-network models. As the basis for this comparison, we use a dataset from recent microfluidic experiments with precisely controlled pore geometry and wettability conditions, which offers an unprecedented benchmarking opportunity. We compare the results of the 14 participating teams both qualitatively and quantitatively using several standard metrics, such as fractal dimension, finger width, and displacement efficiency. We find that no single method excels across all conditions and that thin films and corner flow present substantial modeling and computational challenges.

Summary Unwanted water production is a serious issue in oil- and gas-producing wells. It causes corrosion, scale, and loss of productivity. One method of treating this problem is to chemically reduce unwanted water. This paper discusses the use of polymer systems for this purpose and presents a thorough review of available literature over the last decade. In this paper, field-application data for various polymer systems are summarized over the range of 40 to 150°C (104 to 302°F). These applications cover a wide range of permeabilities from 20 to 2,720 md in sandstone and carbonate reservoirs around the globe. Moreover, the review revealed that the last decade of developments can be categorized into two major types. The first type is polymer gels for total water shutoff in the near-wellbore region, in which a polymer is crosslinked with either an organic or an inorganic crosslinker. The second type is concerned with deep treatment of water-injection wells diverting fluids away from high-permeability zones (thief zones). These thief zones take most of the injected water, which results in a large amount of unrecovered oil. For the total-blocking gels, various systems were identified, such as polyurethane resins, chromium (Cr3+) crosslinking terpolymers, Cr3+ crosslinking foamed partially hydrolyzed polyacrylamide (PHPA), and nanoparticle polyelectrolyte complexes (PECs) sequestering Cr3+ for elongation of its gelation time with PHPA. In addition, polyethylenimine (PEI) was identified to crosslink various polyacrylamide- (PAM-) based polymers. The Petróleos de Venezuela S.A. (PDVSA) Research and Development Center developed a PAM-based thermally stable polymer and an organic crosslinker. The system is applicable for a wide temperature range from 50 to 160°C (130 to 320°F). For the deep modification of water-injection profiles in water-injection wells, two systems were identified: microspheres prepared from PAM monomers crosslinked with N,N′-methylenebisacrylamide and microspheres produced by crosslinking 2-acrylamido-2-methylpropane sulfonic acid (AMPS) with diacrylamides and methacrylamides of diamines (thermally activated microparticles known as Bright Water). This paper highlights all major developments in these areas.

Abstract Nanotechnology application can revolutionalise the additive characteristics and behaviour by tuning particle properties to meet certain operational, environmental, and technical requirements. Hence, the nanotechnological research leading to create some tailored made nanoparticles could be a promising step change research for smart fluids development for different industrial applications. These particles are ultra fines in nature, usually larger than an atom cluster but smaller than ordinary micro particles and thus have very high specific surface area with enormous area of interactions. Due to nano-scale particle dimension, the nano-type fluid additives have both external as well as internal inhibition potential, require a very low additive concentration and thus expected to provide superior fluid properties at a drastically reduced additive concentration. Nano-particles with high thermal stability and affinity to acid gases such as H2S and CO2 will help meet the technical challenges of sour gas environment, deep and geothermal drilling and thus expected to complete a well economically and safely with a drastic reduction in oil and gas exploration and exploitation risk. Identification, screening, selection, and/or development of nontoxic, environment friendly and biodegradable nano-particle-based drilling fluids are expected to meet the current as well as the future environmental norms and regulations for drilling and production in deep water and sensitive environments. This paper provides a detailed description of the likely benefits of emerging nano-particle-based additives in smart fluid design for oil and gas field application, especially for a new generation of drilling and drill-in, completion, stimulation, fracturing, etc fluids for trouble-free drilling, completion and production of oil and gas resources.

Abstract Improved/enhanced oil recovery by tuning the ionic composition of the injection water is currently deemed as new emerging recovery method. In the recent years, extensive research on oil/brine/rock systems has shown that injecting low salinity brines has a significant impact on oil recovery from sandstone reservoirs. Although, the potential for carbonates has not been carefully investigated, some reported studies have excluded carbonates from this effect. In view of research results for the last three years, we demonstrated in previous reports (SPE 137634; SPEREE Journal, vol. 14(5), pp. 578-593, SPE 143550, SPE 141082) that substantial oil recovery beyond conventional waterflooding from carbonates can be achieved by optimizing ionic composition of field injection brine. Also, research confirmed that the driving mechanism is wettability alteration. In this paper, we present the results of new reservoir condition laboratory coreflooding studies, conducted using composite rock samples from different carbonate reservoir, to investigate the impact of ionic content on oil recovery at both secondary and tertiary recovery modes. Also, we report a broad range of laboratory studies addressing role of water ions. In addition, we briefly disclose the results of first-ever field application conducted in a carbonate reservoir to demonstrate the SmartWater Flood potential. The experimental results revealed that substantial tertiary oil recovery beyond conventional waterflooding can be achieved by altering the ionic content of field injection water. Similar potential has been confirmed also in the secondary recovery mode. For recovery mechanisms, the new results confirmed that wettability alteration is the main cause for the substantial increase in oil recovery. Compared to previous reported work, the variation in oil recovery from two different carbonate reservoirs is attributed to the variations in reservoir temperature and also the chemistry of initial formation water. For field application, two field trials confirmed that injection of SmartWater achieved ∼7 saturation units reductions in residual oil beyond conventional seawater flooding. Considering these field trials are the first-ever applications in carbonate reservoirs, they further provided another confirmation that SmartWater Flood is emerging recovery method targeting carbonate reservoirs.

ABSTRACT Microporosity occurs throughout Arab Formation carbonates of Saudi Arabia, and affects the log response, fluid flow properties and ultimate recovery of hydrocarbons in these reservoirs. Qualitative examination of Arab samples indicates that microporosity occurs as four major types: (1) microporous grains, (2) microporous matrix, (3) microporous fibrous to bladed cements, and (4) microporous equant cements. Quantitative estimation of microporosity abundance was measured in two ways: (1) thin section point counts, and (2) pore throat size distributions derived from capillary pressure data. Point count data shows that microporosity can vary widely from sample to sample, ranging from 0% to 100% of the total measured porosity of a sample. Capillary pressure data confirms the volumetric significance of pore throats that are 10 microns or less in size. Variations in microporosity abundance and type appear to be controlled by depositional texture, grain mineralogy and grain microstructure. We suggest that microporosity in Arab Formation carbonates formed diagenetically, via three mechanisms: (1) leaching and incomplete reprecipitation of metastable carbonate, (2) crystal growth contact inhibition, and (3) (locally) endolithic borings of grains.

Abstract In recent years, improved/enhanced oil recovery by tuning the ionic composition of injection water has attracted the attention of the petroleum industry, and currently deemed as new emerging research trend. In view of research results for the last four years, we demonstrated in previous reports (SPE 137634; SPEREE Journal, vol. 14(5), pp. 578-593; SPE 143550, SPE 141082, SPE 154076; SPE 154077) that substantial oil recovery beyond conventional waterflooding from carbonates can be achieved by optimizing the salinity and ionic composition of field injection brine. Similar potential has been confirmed also in the secondary recovery mode. For recovery mechanisms, research confirmed that the driving mechanism is wettability alteration of carbonate rock surface and can be attributed to surface charges alteration, and microscopic dissolution of anhydrite. In this paper, we present the results of two field trials conducted in a carbonate reservoir to demonstrate the SmartWater Flood potential. Both field trials confirmed that in-house research results can be replicated at field scale. Injection of SmartWater revealed a reduction of ~7 saturation units in the residual oil beyond conventional seawater. Considering these field trials are the first-ever applications in carbonate reservoirs, they further provided another confirmation that SmartWater Flood has significant potential to be a new recovery method targeting carbonate reservoirs. A special type of single-well chemical tracer was used in these trials to measure the residual oil in the vicinity of the well following the injection of each water type. During all stages of field trials, careful QA/QC program was put in place to monitor variation in ionic composition in all injected or produced fluids and further insure optimum ionic composition of SmartWater slugs. Several field trials are planned to optimize the current process leading to a multi-well Demonstration Pilot to determine the impact on ultimate recovery and reserves.

ABSTRACT Simultaneous source acquisition technology, also referred to as “blended acquisition,” involves recording two or more shots simultaneously. Despite the fact that the recorded data has crosstalk from different shots, conventional processing procedures can still produce acceptable images for interpretation. This is due to the power of the stacking process using blended data with its increased data redundancy and inherent time delays between various shots. It is still desirable to separate the blended data into single shot gathers and reduce the crosstalk noise to achieve the highest seismic image quality and for standard prestack processing, such as filtering, statics computation, and velocity analysis. This study introduced a new and simple multidirectional vector-median filter (MD-VMF) to separate the blended seismic shot gathers. This method extended the well-known conventional median filter from a scalar implementation to a vector version. More specifically, a vector median filter was applied in many trial directions and the median vector was chosen from among these. We demonstrated the effectiveness of our proposed MD-VMF on simulated data generated by blending synthetic and real marine seismic data.