SPE Journal最新文献

{"title":"Pressure- and Rate-Transient Model for an Array of Interfering Fractured Horizontal Wells in Unconventional Reservoirs","authors":"E. Ozkan, M. Makhatova","doi":"10.2118/215031-pa","DOIUrl":"https://doi.org/10.2118/215031-pa","url":null,"abstract":"\u0000 An analytical solution is presented for pressure- and rate-transient behavior of an array of n parallel and fractured horizontal wells in an unconventional reservoir. Wells are of equal length but otherwise of unidentical properties. Each well has an arbitrary number of uniformly spaced identical, finite-conductivity fractures and is surrounded by a stimulated reservoir volume (SRV). The properties of hydraulic fractures (HFs) and SRVs may vary from well to well. Different properties may also be assigned to the unstimulated reservoir sections between wells. Natural fractures in stimulated and unstimulated reservoir volumes are accounted for by transient dual-porosity idealization. The flow domain is divided into blocks of 1D flow under the trilinear-flow assumption. Solution for each block is obtained analytically and coupled with the solutions for the neighboring blocks by the continuity of pressure and flux at the block interfaces. Drainage volumes of wells are adjusted based on the variation of well production rates because of moving no-flow boundaries between wells. The superposition principle is applied to consider variable-production conditions as well as nonsynchronous production and shut-in schedules of wells. The final solution is in the form of a matrix-vector equation in the Laplace transform domain and inverted into the time domain numerically. The model is robust and reasonably accurate for most practical applications of single-phase oil and gas production from multiple wells in an unconventional reservoir. It is an efficient tool to assess well interference effects for different well completion designs and varying reservoir characteristics. The speed of the model makes it useful for pressure-transient and production-data analysis, as well as for the initial calibration and verification of more complex numerical models.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":null,"pages":null},"PeriodicalIF":3.6,"publicationDate":"2024-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141136275","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Segmentation Study of Deep Shale Gas Horizontal Wells of the South Sichuan Shale Gas","authors":"Yumin Li, Xiaoping Li, Yonggang Duan, M. Wei, Ke Meng","doi":"10.2118/221451-pa","DOIUrl":"https://doi.org/10.2118/221451-pa","url":null,"abstract":"\u0000 The low porosity and low permeability of shale gas reservoirs make fracturing technology an indispensable part of shale gas reservoir development. The initial stage of shale gas development is characterized by shallow direct wells, but with the advancement of drilling and completion technology in the development of unconventional oil and gas reservoirs, horizontal wells and fracturing technology have gradually become the key methods for the effective development of oil and gas reservoirs. “Geology-engineering integration” has gradually become a hot spot in the research of horizontal well fracturing. The factors affecting the development of shale gas reservoirs are subdivided into “geological sweet spot” and “engineering sweet spot” influencing factors. Geological sweet spot refers to the area where the reservoir is rich in hydrocarbons or organic matter; engineering sweet spot refers to the area with good fracturability in the later fracturing and reforming of the reservoir. The shale gas sweet spot area should have the characteristics of high gas content, high fracturable, and high efficiency. Comprehensively evaluating the physical properties and brittleness characteristics can provide certain guidance for shale gas horizontal well segmentation.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":null,"pages":null},"PeriodicalIF":3.6,"publicationDate":"2024-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141142284","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Detectable Radius of Investigation for One Flow Period with Bourdet Derivative","authors":"Lei Jiang, Li Chen, Hua Yu, Morten Kristensen, A. Gisolf, H. Dumont","doi":"10.2118/210150-pa","DOIUrl":"https://doi.org/10.2118/210150-pa","url":null,"abstract":"\u0000 A new definition of the radius of investigation (ROI) is proposed to overcome the ambiguity present in the results from conventional ROI quantification methods. The term ROI is commonly used to quantify the minimum reservoir size or the distance to a potential boundary evaluated through pressure transient testing. However, the various methods available in the literature to quantify ROI often provide different answers stemming from varying assumptions and thus often lead to confusion in terms of the appropriate definition to choose. Although the ROI method developed by Van Poolen is well recognized in the industry, there is still debate about its general applicability because it is limited to a constant-rate flow period and is insensitive to flow rate, flow sequence, gauge resolution, and measurement noise level. This contrasts with operational experience, where a higher flow rate, higher gauge precision, and lower level of measurement noise lead to higher quality pressure transient testing data from which reservoir boundaries, or other features, can be identified farther away from the wellbore. In other words, higher flow rates, better gauges, and lower noise levels can lead to a larger achievable ROI.\u0000 We propose a new definition of ROI, which is the detectable ROI for each drawdown or buildup flow period. The detectable ROI is derived from the actual pressure derivative response and not from a generic model assumption. By defining a derivative noise envelope, the new method clearly identifies the time when the derivative deviates from an unbounded model due to the presence of a boundary and thus provides an estimate of the detectable ROI for the analyzed period.\u0000 This method overcomes the limitations of most conventional methods and provides ROI predictions that depend on flow rate and gauge noise while maintaining a consistent result with the current pressure transient interpretation. While detectable ROI is applicable for general drawdown/buildup pressure transient tests, the concept was developed with deep transient testing (DTT) in mind.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":null,"pages":null},"PeriodicalIF":3.6,"publicationDate":"2024-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141140914","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Automated Reservoir Characterization of Carbonate Rocks using Deep Learning Image Segmentation Approach","authors":"S. Nande, S. Patwardhan","doi":"10.2118/219769-pa","DOIUrl":"https://doi.org/10.2118/219769-pa","url":null,"abstract":"\u0000 The objective of this study is to develop a systematic and novel workflow for the automated and objective characterization of carbonate reservoirs with the help of deep learning architectures. An image database of more than 6,000 carbonate thin-section images was generated using the optical microscope and image augmentation techniques. Five features, namely clay/silt/mineral, calcite, pores, fossils, and opaque minerals, were identified with the help of manual petrography of the thin sections under the microscope. A total of four deep learning models were developed, which included U-Net, U-Net with ResNet34 backbone, U-Net with Mobilenetv2 backbone, and LinkNet with ResNet34 backbone. The Ensemble model of U-Net + ResNet34 and U-Net + MobileNetv2 yielded the highest intersection over union (IoU) score of 75%, followed by the U-Net + ResNet34 model with an IoU score of 61%. The models struggled with class imbalance, which was very prominent in the image database, with classes such as fossils and opaques considered to be rare. The statistical analysis of the relative errors revealed that the major classes play a more important role in increasing the final IoU score as opposed to the common understanding that the rare classes affect the model performance. The novel workflow developed in this paper can be extended to real carbonate reservoirs for time efficient, objective, and accurate characterization.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":null,"pages":null},"PeriodicalIF":3.6,"publicationDate":"2024-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141056323","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Investigation of Asphaltene Precipitation and Reservoir Damage during CO2 Flooding in High-Pressure, High-Temperature Sandstone Oil Reservoirs","authors":"Lei Li, Mingjian Wang, Yu-liang Su, Xiao-gang Gao, Wen-dong Wang, Jia-wei Tu, Xin-hao Wang","doi":"10.2118/214805-pa","DOIUrl":"https://doi.org/10.2118/214805-pa","url":null,"abstract":"\u0000 Asphaltenes are heavy aromatic hydrocarbon compounds contained in reservoir fluids and may precipitate when the reservoir pressure is reduced by production or when gas is injected into the reservoir, and then further deposit on pore-throat surfaces causing reservoir damage. At present, the research on asphaltene precipitation and reservoir damage is carried out in conventional reservoirs, and the influence of CO2 injection under high-pressure, high-temperature (HPHT) conditions has not yet been clearly understood. In this work, we combined perturbed-chain statistical association fluid theory (PC-SAFT) calculation, experiments, phase-state simulation, and numerical simulation to predict the asphaltene precipitation with different pressures, temperatures, and amounts of injected gas and to clarify the influence on reservoir permeability and oil production when using CO2 injection. The results show that the precipitation of asphaltenes in the process of CO2 injection is the desorption of colloid-asphaltene inclusions caused by gas molecules and then the mutual polymerization process between dispersed asphaltene molecules. CO2 injection will increase the amount of precipitation and move the precipitation curve to the right side. The degree of permeability reduction caused by the deposition of asphaltenes in the core is 12.87–37.54%; the deposition of asphaltenes in the reservoir is mainly around the injection/production wells and along the injected gas profile. Considering asphaltenes, the oil recovery degree is reduced by 1.5%, and the injection rate is reduced by 17%. The reservoir pressure, temperature, and physical properties have a strong correlation with the degree of reservoir damage, while the initial asphaltene content has a low correlation. This work will be of great interest to operators seeking to enhance oil recovery by CO2 injection in deep reservoirs.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":null,"pages":null},"PeriodicalIF":3.6,"publicationDate":"2024-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141132287","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Spatiotemporal X-Ray Imaging of Neat and Viscosified CO2 in Displacement of Brine-Saturated Porous Media","authors":"Boxin Ding, A. Kantzas, A. Firoozabadi","doi":"10.2118/214842-pa","DOIUrl":"https://doi.org/10.2118/214842-pa","url":null,"abstract":"\u0000 CO2 storage in saline aquifers may contribute to a 90% share in preventing emissions to the atmosphere. Due to low CO2 viscosity at the subsurface often found in supercritical (sc) conditions, the injected CO2 may spread quickly at the formation top and increase the probability of leakage. This work relates to improved CO2 storage in saline aquifers by effective viscosification of the sc-CO2 at very low concentrations of engineered oligomers and the effectiveness of slug injection of viscosified CO2 (vis-CO2). We present the results from X-ray computed tomography (CT) imaging to advance the understanding of two-phase CO2-brine flow in porous media and firmly establish the transport mechanisms.\u0000 X-ray CT imaging of displacement experiments is conducted to quantify the in-situ sc-CO2 saturation spatiotemporally. In neat CO2 injection, gravity override and adverse mobility ratio may result in early breakthrough and low sweep efficiency. We find cumulative brine production from the fraction collector to be lower than X-ray CT imaging at 2 pore volume (PV) injection. The difference between the two is attributed to the solubility of the produced water in the produced CO2 at atmospheric pressure. We show that when the solubility is accounted for, there is a good agreement between direct measurements and in-situ saturation results.\u0000 There are three reports (two by the same group) that oligomers of 1-decene (O1D) with six repeat units may have marginal CO2 viscosification. The majority of published work by other groups shows that O1D with six repeat units and higher are effective CO2 viscosifiers. In the past, we have demonstrated the effectiveness of an O1D in the displacement of brine by CO2 at a concentration of 1.5 wt%. The effectiveness is examined and identified by three different methods. In this work, we show that the same oligomer is effective at a low concentration of 0.6 wt%. The oligomer slows the breakthrough by 1.6 times and improves the brine production by 34% in the horizontal orientation. X-ray CT imaging results reveal that such a large effect may be from the increase in the interfacial elasticity. We also show that there is no need for continuous injection of the oligomer. A slug of 0.3 PV injection (PVI) of vis-CO2 followed by neat CO2 injection has the same effectiveness as the continuous injection of the vis-CO2. In this work, we also demonstrate the effectiveness of a new engineered molecule at 0.3 wt% that may increase residual trapping by about 35%. The combination of mobility control and residual brine saturation reduction is expected to improve CO2 storage by effective viscosification with low concentrations of oligomers.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":null,"pages":null},"PeriodicalIF":3.6,"publicationDate":"2024-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141029687","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"A Combined Neural Network Forecasting Approach for CO2-Enhanced Shale Gas Recovery","authors":"Zhenqian Xue, Yuming Zhang, Haoming Ma, Yang Lu, Kai Zhang, Yizheng Wei, Sheng Yang, Muming Wang, Maojie Chai, Zhe Sun, Peng Deng, Zhangxin Chen","doi":"10.2118/219774-pa","DOIUrl":"https://doi.org/10.2118/219774-pa","url":null,"abstract":"\u0000 Intensive growth of geological carbon sequestration has motivated the energy sector to diversify its storage portfolios, given the background of climate change mitigation. As an abundant unconventional reserve, shale gas reservoirs play a critical role in providing sufficient energy supply and geological carbon storage potentials. However, the low recovery factors of the primary recovery stage are a major concern during reservoir operations. Although injecting CO2 can resolve the dual challenges of improving the recovery factors and storing CO2 permanently, forecasting the reservoir performance heavily relies on reservoir simulation, which is a time-consuming process. In recent years, pioneered studies demonstrated that using machine learning (ML) algorithms can make predictions in an accurate and timely manner but fails to capture the time-series and spatial features of operational realities. In this work, we carried out a novel combinational framework including the artificial neural network (ANN, i.e., multilayer perceptron or MLP) and long short-term memory (LSTM) or bi-directional LSTM (Bi-LSTM) algorithms, tackling the challenges mentioned before. In addition, the deployment of ML algorithms in the petroleum industry is insufficient because of the field data shortage. Here, we also demonstrated an approach for synthesizing field-specific data sets using a numerical method. The findings of this work can be articulated from three perspectives. First, the cumulative gas recovery factor can be improved by 6% according to the base reservoir model with input features of the Barnett shale, whereas the CO2 retention factor sharply declined to 40% after the CO2 breakthrough. Second, using combined ANN and LSTM (ANN-LSTM)/Bi-LSTM is a feasible alternative to reservoir simulation that can be around 120 times faster than the numerical approach. By comparing an evaluation matrix of algorithms, we observed that trade-offs exist between computational time and accuracy in selecting different algorithms. This work provides fundamental support to the shale gas industry in developing comparable ML-based tools to replace traditional numerical simulation in a timely manner.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":null,"pages":null},"PeriodicalIF":3.6,"publicationDate":"2024-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141141695","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Novel Resin-Coated Sand Placement Design Guidelines for Controlling Proppant Flowback Post-Slickwater Hydraulic Fracturing Treatments","authors":"Mohamed Tarek, Jada Leung","doi":"10.2118/217830-pa","DOIUrl":"https://doi.org/10.2118/217830-pa","url":null,"abstract":"\u0000 Resin-coated sand (RCS) is an effective way for controlling post-stimulation proppant flowback. However, with the shift to slickwater treatment fluids, the “tail-in” placement approach has proved to be less efficient for complete flowback control due to the proppant settling characteristics of using low-viscosity fluids. A new RCS placement approach was developed based on the results of several flowback studies. Trial wells were completed in different US basins with successful results.\u0000 Proppant flowback samples were collected during different stages of drillout and production from wells using slickwater fluid systems. Thirty-five wells, completed by thirteen different operators, within the Permian and MidCon basins were evaluated. All wells were completed using multiple proppant mesh sizes. A total of 375 flowback samples were collected during the drillout and production phases. The samples were sieved, and the results were fed into an in-house material balance model to determine the percentages of different mesh sizes in the flowback samples. The conclusions were used as guidelines for a new placement approach implemented in multiple new wells to control proppant flowback.\u0000 The flowback samples ranged from predominantly lead proppant to a similar proportion of the pumped mesh sizes. Not one of the 35 wells had flowback samples containing the majority tail-in mesh size. This supports the early sand dune assumption, suggesting that the early proppant forms dunes near the wellbore and late sand settles over the existing proppant beds. The use of late RCS appears to have a minimal effect on preventing flowback of the early proppant within a stage utilizing slickwater fracturing. Therefore, RCS efficiency to control proppant flowback with the tail-in method is reduced when used in such slickwater stimulations. To seal the different proppant beds, the new approach recommends pumping multiple RCS steps within a stage. The first RCS step is recommended within the first 10–20%, the second sequence within the first 40–60% of proppant volume, and the third as a tail-in. The exact percentages and step design were based on the results of flowback samples from neighboring wells. The implementation of this approach in more than 30 wells resulted in superior flowback control compared to offset control wells. In all trials, the proppant flowback completely stopped within 1 to 7 days of starting production.\u0000 In this paper, we discuss the drawbacks of the current RCS placement practice while suggesting a new practical approach supported by data. RCS tail-in showed successful flowback control with viscous fracturing fluids and hybrid systems. For slickwater systems, an optimized placement design for RCS throughout the pump schedule provided enhanced flowback control compared to RCS tail-in. Finally, we illustrate the results of field trials in which utilizing the new RCS placement approach successfully reduced flowback.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":null,"pages":null},"PeriodicalIF":3.6,"publicationDate":"2024-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141041440","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Integrated Optimization of Hybrid Steam-Solvent Injection in Post-CHOPS Reservoirs with Consideration of Wormhole Networks and Foamy Oil Behavior","authors":"Senhan Hou, Daihong Gu, Daoyong Yang, Shikai Yang, Min Zhao","doi":"10.2118/212145-pa","DOIUrl":"https://doi.org/10.2118/212145-pa","url":null,"abstract":"\u0000 For this paper, integrated techniques have been developed to optimize the performance of the hybrid steam-solvent injection processes in a depleted post-cold heavy oil production with sand (CHOPS) reservoir with consideration of wormhole networks and foamy oil behavior. After a reservoir geological model has been built and calibrated with the measured production profiles, its wormhole network is inversely determined using the newly developed pressure-gradient-based (PGB) sand failure criterion. Such a calibrated reservoir geological model is then used to maximize the net present value (NPV) of a hybrid steam-solvent injection process by selecting injection time, soaking time, production time, injection rate, steam temperature, and steam quality as the controlling variables. The genetic algorithm (GA) has been integrated with orthogonal array (OA) and Tabu search to maximize the NPV by delaying the displacement front as well as extending the reservoir life under various strategies. Considering the wormhole network and foamy oil behavior and using the NPV as the objective function, such a modified algorithm can be used to allocate and optimize the production-injection strategies of each huff ‘n’ puff (HnP) cycle in a post-CHOPS reservoir with altered porosity and increased permeability within a unified, consistent, and efficient framework.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":null,"pages":null},"PeriodicalIF":3.6,"publicationDate":"2024-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141048408","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Logging-While-Drilling Laterolog vs. Electromagnetic Propagation Measurements: Which Is Telling the True Resistivity?","authors":"Ida Bagus Gede Hermawan Manuaba, Mohammad Aljishi, Marie Van Steene, James Dolan","doi":"10.2118/219772-pa","DOIUrl":"https://doi.org/10.2118/219772-pa","url":null,"abstract":"\u0000 The electromagnetic propagation (EMP) measurement frequently acquired with logging-while-drilling (LWD) tools in high-angle wells is sensitive to geometrical effects that can mask the true formation resistivity. Less commonly used, the LWD laterolog measurement is sometimes perceived as providing data too shallow to give a true formation resistivity (Rt). In this paper, we presents modeling and actual examples to demonstrate that the laterolog can often provide a superior resistivity measurement for formation evaluation to that of the LWD EMP tool.\u0000 We examine the laterolog and EMP resistivities in several high-angle wells crossing carbonate formations in 8.5-in. and 6.125-in. hole sizes. In the 8.5-in. sections, producers and water injectors (high- and low-resistivity ranges) were evaluated. In the 6.125-in. sections, one reservoir sandwiched between two very high-resistivity layers and another borehole in a highly fractured reservoir were examined. The laterolog data were corrected for invasion using a 1D inversion of the memory data. Structure-based forward modeling was used to examine and explain the differences between the laterolog and EMP resistivity measurements.\u0000 In the first example in a thick low-resistivity water reservoir, laterolog resistivity and EMP resistivity agree, showing that the two tools provide the same measurement when no geometrical effects are present.\u0000 In the first part of the second example, a reservoir zone was initially drilled only with the LWD EMP resistivity measurement. The LWD laterolog was run several days later, and the resistivity data read much lower in the relogged section compared with the EMP resistivity. The laterolog 1D inversion was unable to resolve Rt because of the excessively deep invasion that occurred over the course of several days.\u0000 In the second part of the second example, the laterolog resistivity showed a clear conductive invasion profile. While the deepest laterolog real-time resistivity data indicated lower resistivity than the EMP resistivity, the true resistivity, Rt (invasion-corrected 1D-inverted laterolog resistivity), matched the EMP Rt resistivity. This result validated both measurements and emphasized that the differences were due to invasion.\u0000 The first two examples demonstrated that when acquired in normal drilling conditions (within 1–2 hours of drilling the section), the laterolog measurements can provide uninvaded formation resistivity even in the presence of invasion.\u0000 A reservoir in another example was sandwiched between resistive layers that caused difficult-to-explain elevated EMP resistivity readings. Structural modeling reproduced the elevated behavior of the EMP data and explained the differences between resistivity measurements. This result showed that the laterolog is better suited to evaluate resistivity in thin reservoirs where there is a high-resistivity contrast to the adjacent layer.\u0000 Finally, fractured reservoir examples are presented, which show that both th","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":null,"pages":null},"PeriodicalIF":3.6,"publicationDate":"2024-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141049866","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}