Sand Bodies Research Articles

A general framework to optimize fracture parameters in tight gas reservoir of heterogeneous channel sand bodies

Optimizing fracture parameters can unlock the potential of tight gas reservoirs. Various frameworks have been proposed as efficient optimization tools. However, current frameworks are mostly aimed at regular rectangular oil or gas reservoirs. The effect of heterogenous channel sand bodies on fracture parameter optimization has not been discussed. Here, we proposed a general optimization framework. The first step is to establish a heterogeneous channel sand bodies model based on image processing and data interpolation methods. The second step is to couple optimization algorithm and reservoir simulator to optimize fracture parameters. Then the framework is applied to two actual wells in Shaximiao Formation in Sichuan Basin in China. Results show that, the effect of channel sand body on the fracture optimization cannot been ignored. The optimal fractures tend to be concentrated in areas with good physical properties and large control areas. The sand body boundary has a significant control effect on the fracture half-length. For both fracture length and conductivity, double dumbbell shape is better than uniform shape. Our general framework serves as an efficient tool to optimize fracture design in heterogeneous channel sand body, which plays a growing role in enhancing tight gas recovery.

The primary porosity heterogeneity characteristics of braided river sandbody and implications for predicting the current physical properties heterogeneities

Understanding the heterogeneity of reservoirs is crucial for enhancing the efficiency of hydrocarbon exploration and development. The primary porosity of samples from modern braided river sands and outcrops of braided river sandstone was calculated using a model previously proposed by the authors. The characteristic parameters (Vx) for calculating primary porosity are closely related to the architectural–elemental configurations (AEC), and the AEC of braided river sand bodies (BRSD) has apparent effects on the distribution of the primary porosity heterogeneities. Analysis of our results has established a simple primary porosity heterogeneity model of BRSD. The center of braided river channel and mid-channel bars have excellent strong primary petrophysical properties with high primary porosity exceeding 38%. The contact areas between the braided river channel and channel bars exhibit relatively low primary porosities of less than 33%. The area between the center and edge of the braided bars and channels displays medium primary porosities. The nonlinear correlation in the Q–Q plot of the primary porosity and present porosity of samples from BRSD in the Ahe Formation is mainly caused by chemical diagenesis. The present porosity heterogeneity of BRSD in the Ahe Formation is less influenced by compaction and cementation, it predominantly arises from the differential of dissolution. Q–Q plots attempt to correlate the geological information from an individual sample with the heterogeneity of present porosity in BRSD. In addition, by utilizing Q–Q plots of the primary and current petrophysical properties of the sand body, the relative extent of heterogeneity modification caused by different diagenetic processes can be assessed. This assessment is crucial for modeling macroscopic models of physical properties during geological history periods.

Unlocking the Nile Delta subsurface via advanced processing and imaging

The subsurface of the Nile Delta is infamous for challenges that are caused by a variety of geologic features that need to be resolved to unlock the full potential of the basin. The primary cause for many of the issues is the Messinian interval. This is a well-studied regional salt body with significant variation in composition, ranging from mobile shales to sand bodies over contaminated salt to anhydrite. The layer locally shows a hard top and base, which sets up mode conversions and complex multiples. The Messinian is also highly variable in terms of its geometry, thickness, faulting, and rugosity, which results in significant scattering of the seismic wavefield. The problem is further complicated by the presence of mud volcanoes that are scattered throughout the basin. Some of the mud volcanoes are currently active, and others are buried beneath more recent deposits. Free gas is often associated with these structures, and a high degree of lateral and vertical rock property variation is present, leading to complexities in seismic velocity and attenuation. The water depth varies considerably within the basin. Some producing assets exist that straddle the coastline, while others are located in water depths in excess of 1000 m. The transition is not simple due to erosional features on the seabed, leading to complex free-surface multiples. While many discoveries and developments have already been made in the post-Messinian, prospectivity in the basin is now located in the pre-Messinian, with targets ranging in depth from 2 to 10 km. When all of these features are combined, it results in a truly complex geophysical challenge.

Seismic sedimentology analysis of meter-scale thin sand bodies in the Jurassic Qigu Formation, Yongjin area, Junggar Basin

Seismic sedimentology is an interdisciplinary field that integrates sedimentary geology and geophysics to accurately characterize the spatial and temporal distributions of sedimentary systems. This paper focuses on the Qigu Formation in the Yongjin area of the Junggar Basin, China. The objectives are to establish a high-resolution sequence stratigraphic framework and to clarify the types of sedimentary systems present. Various technical methods, including 90° phase adjustment, attribute clustering, red-green-blue attribute fusion, stratal slicing, and seismic phase-controlled waveform indication inversion, are employed to restore the vertical evolution history of the sedimentary system and quantitatively characterize the spatial-temporal distribution of the thin sand bodies in the Qigu Formation. The results revealed that the Qigu Formation is divided into a third-order sequence, consisting of a lowstand systems tract and a lacustrine transgressive systems tract. During the lowstand systems tract, a thick channel sand body developed in the delta front, exhibiting a non-muddy, intermittent normal grading structure. The lacustrine transgressive systems tract features thin, discontinuous channel sand bodies with mud layers, also forming an intermittent normal grading structure. Two distinct types of delta fronts are identified: the first, formed during the lowstand systems tract, is characterized by branching subaqueous distributary channels in a shallow-water environment. The second, associated with the lacustrine transgressive systems tract, displays a network-like distribution of subaqueous distributary channels in a relatively deeper-water environment.

A Petrophysical Properties Evaluation Study of a Niger Delta Field Using Well Logs and Core Data

A petrophysical properties evaluation study of an onshore field “NEMA” was carried out to assess the petrophysical characteristics of the field in the eastern portion of the Niger Delta Basin. This was done in an effort to determine the hydrocarbon prospect and oil productivity potential of the reservoirs. The net/gross thickness was one of the examined parameters. (pay zone thickness), porosity, permeability, fluid saturation which were all inferred from geophysical wireline logs and core data. The wireline logs used in the investigation included density, resistivity, gamma ray, and spontaneous potential logs for five different wells from the “NEMA” oil field. Five reservoirs designated, NEMA 01, NEMA 04, NEMA 07, NEMA 09, and NEMA 12 were identified and correlated across the five wells in the field using gamma ray logs and shale resistivity markers. Based on the computation of petrophysical parameters, the porosity of the reservoirs ranged from 0.22 (22%) to 0.31 (31%); the permeability ranged from 851.58 mD to 1005.05 mD; the average net-to-gross thickness of the reservoir sand bodies was 140 ft; the water saturation value was less than 45%, while the hydrocarbon saturation was greater than 55%. We equally observed that our computed petrophysical parameters from well log data correlated well with the core computed values in NEMA 09. In conclusion, the delineated reservoirs were categorized as good hydrocarbon reservoirs. These results suggest huge hydrocarbon potential and a reservoir system whose performance is considered satisfactory for hydrocarbon production.

Prospects for the allocation of Paleorousels in the subsalt complex of the south-east of the Caspian sedimentary basin

development and features of the formation of the sedimentary complex of the south of the Caspian sedimentary basin are presented. The complex geological structure of the region is mainly due to the influence of tectonic, volcanic and denudation processes on sedimentation. The introduction of terrigenous material deep into the sedimentary basin (Matken-Ushmolinsk, Biikzhal and South Embin zones) by paleorubic flows contributed to the emergence of accumulative shafts and interbranch uplifts composed mainly of clay rocks with alternating siltstone-sandstones. In the paleorusls themselves, coarser sediments were deposited – gravelites and sandstones. The reconstruction of the conditions of formation of sand bodies made it possible to predict their facies composition, morphology and identify patterns of spatial placement, and are also of great interest in the search for oil and gas deposits in deep-lying lithological traps. The prospects of these structures and their resource potential are evidenced by the world experience in identifying large deposits of hydrocarbon raw materials. This is a new highly promising direction of large accumulations of hydrocarbons for the Caspian Basin. The results of drilling deep wells conducted in recent years have made it possible to refine the internal structure, substantiate new facilities in the Late Paleozoic sedimentary complex, and reassess the prospects of oil and gas potential and forecast oil and gas resources of the south of the Caspian Basin.

Analysis of Factors Influencing Tight Sandstone Gas Production and Identification of Favorable Gas Layers in the Shan 23 Sub-Member of the Daning-Jixian Block, Eastern Ordos Basin

The Daning-Jixian Block harbors abundant tight sandstone gas resources. However, significant variations in gas production exist among the different wells within the block. A comprehensive study was conducted on key factors such as sedimentary strata and petrophysical characteristics to elucidate their impact on gas reservoir productivity. Linear regression equations were employed to classify the favorable reservoirs within the study area. The analysis revealed that within the first 6 months of production from the Shan 23 gas layer, daily gas production ranged from 2576.19 to 156,078.17 m3/d, averaging 24,037.9 m3/d. Over the first year, average daily production varied from 2185.05 to 136,806.99 m3/d, averaging 23,469.23 m3/d, indicating relatively stable production from the Shan 23 layer alone. In the dominant central area of the underwater distributary channel delta front in Shan23, the sand body exhibits a superimposed cutting type, resulting in high production rates. Conversely, the sand bodies on the periphery gradually transition to superimposed and isolated types, leading to decreased production. Through a correlation analysis of gas layer thickness, porosity, permeability, and initial gas well production, it was determined that gas production from the wells within the same layer is primarily influenced by gas layer thickness, porosity, and permeability. Gas saturation demonstrates a minimal impact on production according to single-factor analysis. The evaluated factors such as the gas productivity coefficient, energy storage coefficient, and enrichment coefficient exhibited similar distribution patterns across the study area. The high-value areas for the gas productivity coefficient, energy storage coefficient, and enrichment coefficient are concentrated in distributary channel zones and delta lobes. In contrast, regions with underdeveloped skeletal sand bodies generally display lower values for these parameters. The linear relationships between these parameters and the average gas production were calculated to further classify the favorable reservoirs in the study area. This study aimed to establish a scientific basis for the efficient development of the tight sandstone gas reservoirs within the Daning-Jixian Block.

Prediction of deep low permeability sandstone seismic reservoir based on CBAM-CNN

The prediction of sand body is a key focus in evaluating reservoir distribution, playing a crucial role in oil and gas exploration and development. To clarify the development characteristics of the sand body in the Huangyan structural belt of the Xihu Sag and effectively identify the hidden channel, a new approach is proposed. This approach incorporates a Convolutional Block Attention Module (CBAM) into a Convolutional Neural Network (CNN). Well logging and seismic data were used to predict the distribution of sand body in the lower section of the Huagang Formation (H12). Firstly, based on known sand-stratum ratio data and well-side seismic data, the seismic attributes that are sensitive to the reservoir response are preferred through correlation analysis, which are used to construct a Polynomial Linear Regression (PLR) model to obtain the preliminary sand distribution prediction results. Secondly, the grid is divided according to this result. Then, three sample selection methods, namely proportional, fixed-range, and random, are used to construct three sample sets in conjunction with the geologic model guide. Finally, CBAM-CNN, CNN, Random Forest (RF), Support Vector Machines (SVM), and Backpropagation Neural Network (BPNN) are utilized for sand body prediction. The results indicate that when using the same model, the sample set selected by the fixed-range selection method yielded the best prediction outcome. When using the same sample set, the CBAM-CNN model outperformed the others. Among various strategies, training the CBAM-CNN model with the sample set derived from the fixed-range selection method led to the highest test set R2 of 0.913. The results of the sand body distribution indicate that fine river channels are more continuous, and reservoir boundaries are clearer, significantly outperforming other schemes. This outcome can serve as a guide for further reservoir delineation.

Sedimentological and diagenetic facies of tight sandstones in lacustrine delta-front: A case study of the Jurassic Lianggaoshan Formation, eastern Sichuan Basin

In this study, taking the Jurassic Lianggaoshan Formation (J1l) tight sandstones in the eastern Sichuan Basin as an example, the types and well-logging responses of main sedimentological and diagenetic facies in the lacustrine delta-front are investigated based on summarizing the sedimentary characteristics and reservoir properties. Subsequently, further validation and application are conducted in the study area through machine learning. Research results show that the J1l lacustrine delta-front in the eastern Sichuan Basin mainly develops subaqueous distributary channels and mouth bar sand bodies, exhibiting typical densification reservoirs, with porosity and permeability distributed between 0.48% and 11.24% (av. 3.87%) and 0.0003–0.653 × 10−3 μm2 (av. 0.026 × 10−3 μm2), respectively. Strong compaction and strong cementation are the primary factors leading to densification, whereas chlorite coatings and weak dissolution play constructive roles in preserving some primary pores, creating a small amount of dissolution pores, and enhancing permeability. In terms of manifestation, the pore-throat content with a radius greater than 0.006 μm governs the reservoir quality. Furthermore, five types of diagenetic facies are identified in the J1l subaqueous distributary channels and mouth bars: strong compaction facies (Type I), strong cementation facies (Type II), chlorite-coating and intergranular pore facies (Type III), weak dissolution and intragranular pore facies (Type IV), and medium compaction and cementation facies (Type V). Overall, the thick and coarse-grained subaqueous distributary channels can be considered as the preferred exploration targets for tight oil and gas, with type III and type IV diagenetic facies being the most favorable reservoirs, characterized by well-logging responses of high AC and low GR, DEN, and RT. Based on the fine division of sedimentological and diagenetic facies, establishing well-logging interpretation models and then employing machine learning to achieve sweet spot reservoir prediction can provide valuable insights for tight oil and gas exploration in regions lacking core data.

Study and Application of Fine Dissection Methods for Inter-river Sands in Large Shallow River-controlled Delta Plains

Applying the data of coring wells and logging curves of dense well network, identifying the sedimentary sands of different river systems and contemporaneous periods with the methods of standard layer approximation control and comparison of reference layer combinations, establishing a set of logging phase models of inter-river sands, and using the models as a guideline for micro-phase identification, we have studied the distribution and combination characteristics of the micro-phase sands of the inter-river sand bodies, as well as the type of connectivity with the sand bodies of the river and the relationship, and clarified the distribution characteristics and residual oil distribution of the sand bodies of the inter-river sands. The characteristics of different types of sand body movement and residual oil distribution were clarified, effective dredging methods were proposed, and measures such as oil testing and fracturing were taken, which played an important role in guiding the adjustment and dredging of oil fields in the late stage of high water content.

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.

Prediction of Oil Source Fault-Associated Traps Favorable for Hydrocarbon Migration and Accumulation: A Case Study of the Dazhangtuo Fault in the Northern Qikou Sag of the Bohai Bay Basin

In order to study the distribution pattern of oil and gas near the lower-source, upper-storage type of oil source faults in the hydrocarbon-bearing basins, a set of prediction methods favourable to oil and gas migration and accumulation were established by superimposing the parts of the oil source fault-associated traps, the contiguously distributed sand bodies and the lateral sealing position of faults. The trap associated with a fault can be determined by the fault’s convex part on the fault plane’s morphology map, the fault throw displacement curve and the intersection of faults on the structure map. The set of sand bodies can be determined by the sand-to-shale ration of the formation. The lateral sealing position of faults can be investigated by the shale content of the fault. This study is based on our case study of the Dazhangtuo Fault in the lower sub-member of the 1st member (Es1L) of the Shahejie formation in the northern Qikou Sag of Bohai Bay Basin. The results illustrate 4 fault nose traps formed by fault line deflection in the Es1L formation of the Dazhangtuo Fault, 2 each in the middle and eastern end. The Dazhangtuo Fault is favorable for oil and gas migration except at the eastern and western ends and the middle part of the fault. The fault-associated traps in the Es1L formation that are highly favorable for hydrocarbon migration and accumulation (overlapping site of associated traps and favorable location for oil and gas migration) are distributed in the eastern and central parts of the Dazhangtuo Fault. In contrast, those moderately favorable for hydrocarbon migration and accumulation (associated trap at a certain distance from the favorable location for oil and gas migration in the Dazhangtuo Fracture) are locally distributed in the east. Both traps are conducive to accumulating hydrocarbons from the underlying source rock in the Es3 formation. Such observations are consistent with the current confirmed hydrocarbon distribution, thus validating the feasibility and accuracy of predicting the distribution of traps related to oil source faults favorable for hydrocarbon migration and accumulation, it can be used to guide the exploration of the lower-source, upper-storage type of hydrocarbon accumulations in the hydrocarbon-bearing basins.

Prediction of tight sandstone reservoirs by multiwave joint prestack inversion technology: A case study of the Qiulin area in the Sichuan Basin

The Shaximiao (SXM) Formation of the Middle Triassic in the central Sichuan Basin is a river-lake sedimentary system with an average burial depth of 2800 m. The channel sand bodies of the SXM Formation in the Qiulin area are developed with large lateral variation and high- and medium-porosity sand. This leads to great differences in the seismic response and difficulty in predicting the sand bodies and reservoirs using P-wave data. We carry out well-log analysis for different types of sand bodies. The no. 8 sand body of high porosity can be effectively identified using P-wave impedance (PI). Whereas for the no. 7 sand body of relatively lower porosity (mainly due to the higher shale content in the no. 7 sand compared with the no. 8 sand), sandstone and mudstone can be distinguished using S-wave impedance (SI), and reservoirs can be recognized by the P- to S-wave velocity ratio ([Formula: see text]/[Formula: see text]). Based on the PP wave and the P-to-S converted wave (PS wave) (after matching) angle-stacked data, a prestack inversion of multicomponent data is performed. Multiwave joint inversion results (SI and [Formula: see text]/[Formula: see text]) have better accuracy and stronger stability than the PP-wave inversion in practical application. In addition, the PI of the joint inversion more clearly describes the distribution and boundaries of the channel sand and better matches the prediction and drilling data in sand 8. The SI of the joint inversion can identify subtle sand bodies (weak PI contrast) that are difficult to be detected by PP-wave inversion. The distribution of the reservoir predicted by the [Formula: see text]/[Formula: see text] of the joint inversion is clearer (the no. 7 sand body) and better than that by the PP-wave inversion. This study demonstrates the advantage of the multiwave joint inversion technology in tight sand identification.

Application of the high-resolution layer-stripping constrained seismic inversion method in thin reservoirs: a case study of Triassic reservoir prediction in Lunnan, Tarim Basin, NW China

The Lunnan Oilfield’s Triassic reservoir is a braided river delta deposition, exhibiting notable characteristics such as rapid lateral sand body changes, thin reservoir thickness, and deep reservoir burial. However, the conventional seismic inversion technique used in this geological context is hindered by the low accuracy of the low-frequency model, resulting in inversion outcomes with limited vertical resolution. Consequently, accurately characterizing the reservoir distribution becomes challenging, posing a significant obstacle for the subsequent exploration and development. In this study, we introduce an enhanced seismic inversion approach using high-resolution layer-stripping constraints. The process begins with the creation of a fine-grained layer sequence grid on wells through Integrated Prediction Error Filter Analysis (INPEFA) technology. Subsequently, this grid aids in interpreting high-resolution sequence layers on the seismic volume, obtained through a frequency division RGB (Red, Green, and Blue) fusion technique. Finally, a novel nonlinear stochastic inversion method is formulated, utilizing the high-resolution sequence to refine both the initial model and inverted results. This innovative seismic inversion technique significantly enhances accuracy, particularly in predicting thin reservoirs, approximately 3 meters thick. The application of this method in a case study on Triassic reservoir prediction in Lunnan, Tarim Basin, NW China, demonstrates its promising future applications.

Petrophysical Evaluation of Arkoses Reservoirs Based on Well Logs and Plug Samples: A Case Study From Alagamar Formation, Southeastern Portion of Onshore Potiguar Basin, Brazil

The Potiguar Basin is a sedimentary basin located in northeastern Brazil. It covers about 48,000 km² and extends from onshore to offshore. The onshore basin is thought to have formed during the Late Cretaceous, as a result of the opening of the Equatorial South Atlantic Ocean, filled with a thick sequence of sedimentary rocks, including sandstones, shales, and limestones, which were deposited in a variety of processes, including marine, deltaic, and fluvial. The study area is in the southern portion of the basin and the reservoir is composed of arkose sandstones deposited by alluvial fan and fluvial systems of the Upanema Member of the Alagamar Formation, which belongs to the post-rift phase of the Potiguar Basin. Recently, new drilling campaigns revealed a reservoir heterogeneity in these deposits, which requested a new petrophysical approach. Using conventional well logs and petrophysical laboratory analysis of plug samples, this study evaluated the best way to calculate the effective porosity, and shale volume and to understand the stratigraphic controls in the distribution of these properties. Three reservoir zones were mapped: the basal one, Zone 3, has disconnected sand bodies, low porosity, and high shale content; Zone 2 has better petrophysical properties, lateral distribution, and connectivity between the fans and Zone 1 is the better reservoir zone with larger sand bodies, higher porosity values, and well-connected fans.

A novel approach to understanding the genesis and distribution of widespread reservoirs at the basin edge: A case study of gas-bearing sandstone in the Sangonghe Formation, Junggar Basin, Western China

A 20 m thick sandstone drilled in the second member of the Sangonghe Formation in the Qianshao area of the Junggar Basin has been identified to be a high-quality gas-bearing reservoir. However, recent missions reveal an uncertainty in reservoir distribution and bring high risk to the subsequent gas development, although the gas-bearing reservoir has been encountered by several drillings and proved to be widespread. To investigate the accurate distribution and reveal the evolution of the reservoir, we reconstruct the stratigraphic framework and depositional stages by a high-revolution sequence stratigraphic method, effectively identify the gas-bearing reservoir by seismic attributes refusion and seismic stratigraphic slices, and finally map the distribution strata distribution at different stages. The results indicate that the landward onlap phenomenon in the seismic data indicates a retrogradational stratigraphic structure during the water level rise rather than the equal-thickness stratigraphic pattern under stable water conditions. According to the retrogradational stratigraphic structure, the real driver for the widespread characteristic of a gas-bearing reservoir is the backward staggered movement of multistage sand bodies during the transgressive process rather than single-stage deposition. The fusion of seismic acoustic impedance and main frequency attributes provides an effective survey to identify the accurate distribution of the reservoir, by which interpretation of a stratigraphic slice along the vertical centerline of the reservoir extracted from the multiattribute fusion survey can present the distribution and evolution of the three stages on only one map. Achieved by an appropriate interpretation on the map, two sandy debris flow bodies are identified as being deposited at the bottom successively during the first two transgressive stages. They are completely staggered in the source direction with a clear boundary between well Qs9 and Qs7. Subsequently, the subsequent rise of the water level led to the deposition of a large-scale multibranch shallow-water delta, which exhibits the characteristics of multistage, multisource, and multibranch. The results not only advance our comprehension of widespread sand bodies but also furnish fundamental insights for the development of lithologic condensate gas reservoirs in the Qianshao area.

Infill Well Location Optimization Method Based on Recoverable Potential Evaluation of Remaining Oil

Infill well location optimization poses significant challenges due to its complexity and time-consuming nature. Currently, determining the scope of infill wells relies heavily on field engineers’ experience, often using single indices such as the remaining oil saturation or abundance of remaining oil reserves to evaluate the potential of remaining oil. However, this approach lacks effectiveness in guiding the precise tapping of remaining oil in ultra-high water cut reservoirs. To address this, our study comprehensively considers the factors influencing the recoverable potential of remaining oil in such reservoirs. We characterize the differences in reservoir heterogeneity, scale of recoverable remaining oil reserves, water flooding conditions, and oil–water flow capacity to construct a quantitative evaluation index system for the recoverable potential of remaining oil. Recognizing the varying degrees of influence of different indices on the recoverable potential of remaining oil, we determine the objective weight of each evaluation index by combining an accelerated genetic algorithm with the projection pursuit model. This approach enables the construction of a recoverable potential index for remaining oil and forms a quantitative evaluation method for the recoverable potential of remaining oil in ultra-high water cut reservoirs. Subsequently, we establish a mathematical model for infill well location optimization, integrating and optimizing the infill well location coordinates, well length, well inclination angle, and azimuth angle. Using the main layer sand body of an oilfield in Bohai as a case study, we conducted evaluations of the remaining oil potential and infill well location optimization. Our results demonstrate that the assessment of the remaining oil potential comprehensively characterizes the influence of the reservoir’s physical properties and oil–water diversion capacity on the remaining oil potential across different regional positions. This evaluation can effectively guide the determination of infill well location ranges based on the evaluation results. Furthermore, infill well location optimization can effectively enhance reservoir development outcomes.

The Environmental History of the Navazo Agroecosystem in Late Holocene Sand Bodies Along the Atlantic Coast of Andalusia, Spain

ABSTRACT Since the late Spanish Enlightenment, the agroecosystem of the Atlantic coast of Andalusia, through which coastal dune systems are cultivated via sunken gardens between sand berms, have attracted scholarly attention. The environmental history of these systems, known as Navazo, is the focus of this article. Through analysis of historical aerial photographs, we identify eight areas in which traditional Navazo land use was practiced. By studying landscape diversity and historical documentation we identify key aspects of the emergence and evolution of this agroecosystem. The results of this study indicate that Navazos originated through a combination of the natural properties offered by the region's coastal dune geomorphology, which was cultivated as vineyards since ancient times, as well as external cultural influences. Coinciding with the popularisation of potato consumption in the eighteenth century, earlier vineyards were, in some cases, completely replaced by Navazos. Due to transformations in traditional land use practices, created a contemporary version of the Navazo. The location and physical configuration of the Navazos, meanwhile, display strong similarities with archaeological remains of Plot-and-Berm agroecosystems from the southeastern Mediterranean dating from the Early Islamic period. This study presents evidence to better understand the function, cropping practices and irrigation of these systems. .

Seismic Prediction Technology for Channel Sand Body of Fuyu Oil Layer in Xinmin Area, Southern Songliao Basin

The Fuyu reservoir in Xinmin area is a delta plane-front facies deposit, and the channel sand body in this area is the main reservoir of oil and gas. Due to the complex sedimentary environment, the sand body shows great variation in thickness and distribution. In this study, the method of combining well vibration, model forward modeling and stratum slicing are used to predict the sandstone bodies of different thickness successfully. Especially for the thin sand body with a thickness of less than 5 meters, this study found that the GR curve can effectively distinguish sandstone and mudstone through the intersection analysis of logging curves, and applied the GR curve co-simulation inversion technology to perform fine characterization. In addition, the study also reveals that the northeastward twisting fault zone in Xinmin area is a favorable accumulation area of the reservoir, which provides a new direction for oil and gas exploration. This study not only improves the accuracy of sandstone prediction, but also provides a valuable reference for oil and gas exploration under similar complex geological conditions.