Day 1 Mon, September 30, 2019最新文献

{"title":"Early Warning Systems - Using PTA Analysis of DFITs to Understand Complex Hydraulic Fractures and Optimize Treatment Designs","authors":"A. K. Nicholson, R. Hawkes, R. Bachman","doi":"10.2118/196194-ms","DOIUrl":"https://doi.org/10.2118/196194-ms","url":null,"abstract":"\u0000 This paper outlines methods to characterize hydraulic fracture geometry and optimize full-scale treatments using knowledge gained from Diagnostic Fracture Injection Tests (DFITs) in settings where fracturing pressures are at or above the overburden gradient.\u0000 Hydraulic fractures, whether created during a DFIT or a larger scale treatment, are usually represented by vertical plane fracture models. These models work well in a relatively normal stress regime with homogeneous rock fabric where fracturing pressure is less than the Overburden (OB) pressure. However, many hydraulic fracture treatments are pumped above the OB pressure. This high pressure may be caused by near well friction or tortuosity but may also be the result of more complex fractures in multiple planes.\u0000 Bachman et al (2012, 2015), Hawkes et al (2018) and Nicholson et al (2019) advanced DFIT analysis by using the Pressure Transient Analysis (PTA) technique. This allows the identification of flow regimes useful for understanding fracture geometry and closure behavior beyond that available from more familiar G-function analysis techniques. In this paper DFITs from the Duvernay, Montney, Rock Creek and Cardium formations of Western Canada are analyzed using the PTA method. Particular attention is given to Early-Time Flow Regimes (ETFRs) present between the end of pump shut-down (End of Job Instantaneous Shut-In Pressure, EOJ ISIP) and the 3/2-slope Nolte flow regime. Identification of pressure gradients at the start and end of these flow regimes is of vital importance to the interpretation process. This allows the authors to build on case histories of DFIT-derived fracture geometry interpretations presented in Nicholson et al (2017, 2019).\u0000 Procedures are proposed for picking Farfield Fracture Extension Pressure (FFEP) in place of conventional IIP estimates while distinguishing between storage, friction and tortuosity vs. fracture geometry indicators. Analysis of FFEP and ETFRs combined with the context of rock fabric and stress setting are useful for designing full-scale fracturing operations. A DFIT may help identify potentially problematic multi-plane fractures, predict high fracturing pressures or screen-outs. Fluid and completion system designs, well placement and orientation may be adjusted to mitigate some of these effects using the intelligence gained from the DFIT early warning system.","PeriodicalId":325107,"journal":{"name":"Day 1 Mon, September 30, 2019","volume":"57 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131696151","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Deployment of Pressure Hit Catalogues to Optimize Multi-Stage Hydraulic Stimulation Treatments and Future Re-Fracturing Designs of Horizontal Wells in Horn River Shale Basin","authors":"A. Shokri, R. Chalaturnyk, D. Bearinger","doi":"10.2118/196221-ms","DOIUrl":"https://doi.org/10.2118/196221-ms","url":null,"abstract":"\u0000 Continuous monitoring of wellhead pressures, captured from passive wellbores on a multi-well pad during fracturing operation, has been used as a cost efficient diagnostic tool to better characterize stimulated fracture network and reservoir drainage in Horn River Shale Basin. This paper aims to generate pressure hit catalogues and to quantify their effectiveness to deliver real-time on-site improvement in completion treatments, parent/child interactions, and re-fracturing designs.\u0000 Pressure data of a multi-well pad was initially analyzed to establish measurable attributes for identification of hydro-mechanic responses from direct hydraulic communications. A fully-coupled hydro-mechanical code, with explicit inclusion of discontinuities, explored the interaction mechanisms across natural and induced fractures by reproducing observed pressures of passive wells. Employing multivariate experimental design on a subset of pressure data, pressure hit catalogues were generated with notion to the sensitivity of hydro-mechanical properties of fracture/intact rock, geometrical/statistical properties of fracture network, in-situ stresses, and completion design. Using the unexploited subset of pressure data, the practicality of pressure catalogues was verified against coupled simulations.\u0000 The pre-processing of pressure data, to assign attributes to pressure hits, was found essential for analysis of interference mechanisms during fracture treatments prior to incorporating the data into a coupled simulation. Explicit modeling of discrete fractures allowed to evaluate how key sensitive parameters, mainly fracture/intact rock properties, and altered stress environment due to continuous multi-stage fracturing operation, could affect passive pressure signature. Using a subset of pressure hit data obtained from a multi-well pad in Horn River Shale Basin, the calibrated coupled simulations helped to constrain the statistical complexity of fracture network realizations, which ultimately observed to closely align with available microseismic data. The efforts went into the calibration of pressure/stress shadows, using wellhead pressure data at subsequent stages, were summarized. Given the model size and dealing with too large data sets, history-matching of individual pressure hits proved to be computationally intensive. The steps to generate and employ pressure hit catalogues were also illustrated. The results obtained from application of pressure catalogues on the unexploited subset of pressure data indicated close agreement with coupled numerical simulation. A procedure in potential deployment of pressure hit catalogues for real-time modification of multi-well completion and re-fracturing design was lastly provided.\u0000 Because of the inherited uncertainty associated with locating the subsurface origin of passive pressure responses, yet measured at wellhead, more robust interpretation techniques are required for a better on-site assessment of fracturing operations. Th","PeriodicalId":325107,"journal":{"name":"Day 1 Mon, September 30, 2019","volume":"59 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131777791","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"3D Petroleum Systems Modeling of Block 18, Sab'atayn Basin, Onshore Western Yemen: A Quantitative Integrated Assessment of Petroleum Generation, Migration, Losses, and Saturations of the Unconventional Shale/Tight Reservoirs of Madbi Formation.","authors":"Ameen N. Al-Maqtari, A. Saleh, Adel Al-Haygana, Jaber Al-Adashi, Abdulkhalek Alogily, C. Warren, E. Mavridou, N. Schoellkopf, S. S. Husein, A. Ahmad, Z. Baig, N. A. Teumahji, Surenthar Thiakalingam, W. Khan, Nicole Masurek, Carlos Andres Sanchez Torres","doi":"10.2118/195989-ms","DOIUrl":"https://doi.org/10.2118/195989-ms","url":null,"abstract":"\u0000 A 3D petroleum systems model (PSM) of Block 18 in the Sab'atayn basin, onshore western Yemen, was constructed to evaluate the untapped oil and gas potential of the Upper Jurassic Madbi formation. 3D PSM techniques were used to analyze petroleum generation for conventional reservoirs and the petroleum saturations retained in the source rock for the unconventional system. Block 18 has several proven petroleum systems and producing oil and gas fields. The principal source rocks are within the Madbi Formation, which comprises two units, the Lam and the Meem members. Both contain transgressive organically rich \"hot\" shales with total organic carbon (TOC) of 8 to 10%; these are located stratigraphically at the base of each member. Additional organic-rich intervals within the Lam and Meem are less-effective source rocks, with lower TOC values.\u0000 The PSM consisted of 17 depositional events and 2 hiatuses. To accurately replicate geochemical and stratigraphic variations, the Lam and Meem members were further divided into sublayers. The model was calibrated to present-day porosity, permeability, and pressure data, and it incorporated vertical and lateral lithofacies and organic facies variations. Further calibrations used observed maturities (vitrinite reflectance and pyrolysis Tmax) and present-day temperatures and considered laterally variable heat flow from the Early Jurassic to the Late Miocene. Finally, petrophysical analyses from wells provided calculated hydrocarbon saturations, which were used to calibrate the saturation output from the model. The model satisfactorily reproduces the distribution of the main gas and oil fields and discoveries in the study area and is aligned with well test data.\u0000 Maturity results indicate that the upper Lam intervals currently sit within the main to early oil window but are immature at the edges of Block 18 (based on the Sweeney and Burnham Easy R0% kinetics). The lowest Lam unit enters the wet gas window in the center of the block. The underlying Meem member ranges from wet gas to early oil window maturity. Like the Lam, the Meem remains immature along the edges of Block 18. However, in the south of the block, the richest source rocks within the Meem are mainly in the oil window. The degree of transformation of the Meem and Lam varies throughout the members. The model predicts that, at present, the lowest part of the Meem, containing the greatest TOC, has 90% of its kerogen transformed into hydrocarbons.\u0000 The model confirms that the Madbi formation is a promising unconventional shale reservoir with a high quantity of hydrocarbons retained within it. Despite the higher quantity of hydrocarbons retained in the upper Meem, in terms of liquid and vapor hydrocarbons predicted in this model, the lower Lam is the most-prospective conventional tight sand reservoir, and the Meem has very small potential as tight sand reservoirs. This study provided a novel application of 3D PSM technology to assess new unconventional as we","PeriodicalId":325107,"journal":{"name":"Day 1 Mon, September 30, 2019","volume":"122 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"132008030","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Reconsideration of Steam Additives to Improve Displacement Efficiency: Can New Generation Chemicals be Solution for Steam Induced Unfavorable Wettability Alteration?","authors":"R. Pratama, T. Babadagli","doi":"10.2118/195833-ms","DOIUrl":"https://doi.org/10.2118/195833-ms","url":null,"abstract":"\u0000 In this paper, contact angles in a rock/heavy-oil/steam system were measured to observe the degree of wettability alteration when unconventional chemicals were added to steam. A heavy-crude-oil obtained from a field in Alberta (27,780 cP at 25°C) was used in all contact angle measurements and the measurements were repeated on different types of substrates (quartz and calcite). In addition to this observation, surface tension tests between heavy-oil and steam were also conducted to study the change in interfacial properties. All measurements in this research were conducted at a range of temperatures up to 200°C in a high-temperature-high-pressure IFT device. In gaining a comprehensive evaluation of this mechanism, several impacting factors such as pressure, phase change, and type of rock were taken into consideration and evaluated separately. Different types of novel chemical additives—biodiesel, Switchable-Hydrophilicity Tertiary Amines (SHTA), nanofluids (dispersed SiO2 and ZrO2), ethers, alcohols, and chelating agents—were ere applied to the steam with a range of concentrations throughout surface tension and contact angle measurements to evaluate wettability alteration performance at steam temperature and pressure.\u0000 The observation presented that pressure does not contribute substantially to the wettability state and was perceived to be more oil-wet in steam conditions—as also confirmed by our previous research. The irreversible mechanism of wettability state was the result when phase change occurred with the presence of brine. Wettability alteration and surface tension reduction in steam condition were achieved after involving these unconventional chemicals, an example being in the steam with biodiesel application. In addition, optimum chemical concentration was also observed through surface tension and contact angle measurements.\u0000 The study and analysis of chemical additives applications provides a stronger understanding of steam-induced wettability alteration mechanisms in a rock/heavy-oil/steam system. In summary, conventional steam additives can be altered by these novel chemicals that are both cheaper and more thermally stable, thus showing potential and appearing promising for steam wettability improvement and surface tension reduction in steam applications.","PeriodicalId":325107,"journal":{"name":"Day 1 Mon, September 30, 2019","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127455066","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"A New Strategy for Developing Horizontal Well Inner Potential Based on Fiber Optic Distributed Acoustic Sensing Monitoring","authors":"Li Li, Qiyuan Luo, Qi Xiong","doi":"10.2118/196219-ms","DOIUrl":"https://doi.org/10.2118/196219-ms","url":null,"abstract":"\u0000 An optical fiber has been utilized to continuously acquire liquid production profiles in horizontal well in X oilfield. The results obtained from the dynamical monitoring system confirm the time-varying law of the physical property under the condition of high-water flooding, which can serve as the guidelines to explore the potential of remaining oil in high water-cut/high recovery factor oilfield.\u0000 Usually, the sound wave shows different propagation speeds in different medium, which is the basic principle of this test. Firstly, optical cable is used for sound wave detection and signal demodulation.Meanwhile, a series of other processes are applied to calculate the sound velocity of mixed medium; Then the volume velocity and holdup of mixed medium for each phase are determined.The measure of liquid-producing profile along the whole horizontal well has been realized in real time. Finally, numerical simulation model considering the time-varying physical properties is established based on the core flooding laboratory experiment. This result will provide guidelines for the exploration of remaining oil in the well.\u0000 The results obtained from optical fiber monitoring system during last two years show that 80% of the fluid produced from the 502-meter horizontal well is mainly contributed to the first 90-meter horizontal section. Experimental results of core flooding under excessive water flooding (2000 pore volume) indicate that the permeability is 1.4 times of the original. The results of numerical simulations considering the time-varying physical properties illustrate that there is still internal remaining oil along the horizontal well section. So, the strategy of exploiting potential oil is proposed using an accurate directional water plugging, which will decrease 10% water cut and obtain more recoverable reserves.\u0000 Based on the dynamical monitoring results of optical fiber, this paper innovatively provides the strategy of exploiting potential remaining oil in the horizontal wells, which can provide a valuable suggestion for offshore oilfield with high productivity at high water-cut stage.","PeriodicalId":325107,"journal":{"name":"Day 1 Mon, September 30, 2019","volume":"58 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"126277603","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Integrated Characterization of the Fracture Network in Fractured Shale Gas Reservoirs—Stochastic Fracture Modeling, Simulation and Assisted History Matching","authors":"Yonghui Wu, Linsong Cheng, J. Killough, Shijun Huang, Sidong Fang, P. Jia, R. Cao, Yongchao Xue","doi":"10.2118/195928-ms","DOIUrl":"https://doi.org/10.2118/195928-ms","url":null,"abstract":"\u0000 The large uncertainty in fracture characterization for shale gas reservoirs seriously affects the confidence in making forecasts, fracturing design, and taking recovery enhancement measures. This paper presents a workflow to characterize the complex fracture networks (CFNs) and reduce the uncertainty by integrating stochastic CFNs modeling constrained by core and microseismic data, reservoir simulation using a novel edge-based Green element method (eGEM), and assisted history matching based on Ensemble Kalman Filter (EnKF).\u0000 In this paper, the geometry of CFNs is generated stochastically constrained by the measurements of hydraulic fracturing treatment, core, and microseismic data. A stochastic parameterization model is used to generate an ensemble of initial realizations of the stress-dependent fracture conductivities of CFNs. To make the eGEM practicable for reservoir simulation, a steady-state fundamental solution is applied to the integral equation, and the technique of local grid refinement (LGR) is applied to refine the domain grids near the fractures. Finally, assisted-history-matching based on EnKF is implemented to calibrate the DFN models and further quantify the uncertainties in the fracture characterization.\u0000 The proposed technique is tested using a multi-stage fractured horizontal well from a shale gas field. After analyzing the history matching results, the proposed integrated workflow is shown to be efficient in characterizing fracture networks and reducing the uncertainties. The advantages are exhibited in several aspects. First, the eGEM-based Discrete-Fracture Model (DFM) is shown to be quite efficient in assisted history matching of large field applications because of eGEM’s high precision with coarse grids. This enables simulations of CFNs without upscaling the fractures using continuum approaches. In addition, CFNs geometry can be generated with the constraints of core and microseismic data, and a primary conductivity of CFNs can be generated using the hydraulic fracturing treatment data. Moreover, the uncertainties for CFNs characterization and EUR predictions can be further reduced with the application of EnKF in assimilating the production data.\u0000 This paper provides an efficient integrated workflow to characterize the fracture networks in fractured unconventional reservoirs. This workflow, which incorporated several efficient techniques including fracture network modeling, simulation and calibration, can be readily used in field applications. In addition, various data sources could be assimilated in this workflow to reduce the uncertainty in fracture characterization, including hydraulic fracturing treatment, core, microseismic and production data.","PeriodicalId":325107,"journal":{"name":"Day 1 Mon, September 30, 2019","volume":"120 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128018420","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Ears On Wells: Reservoir Delineation and Monitoring Using True 3D Imaging Approaches","authors":"A. R. Ghazali, M. F. Rahim, M. H. M. Zahir, M. Muhammad, M. A. Mohammad, K. Z. A. Aziz","doi":"10.2118/195954-ms","DOIUrl":"https://doi.org/10.2118/195954-ms","url":null,"abstract":"\u0000 The key objectives were to achieve better seismic resolution and spatial delineation in very heterogeneous reservoirs. We decided to supplement simultaneously the surface 3D multi component seismic acquisition by placing additional fiber optic live receivers in the subsurface via a \"True-3D\" experiment without shutting down the oil production. The most cost-effective method to snapshot this wavefield propagation downhole is by utilizing fiber optic Distributed Acoustic Sensing (DAS). The borehole 3D VSP data were acquired by sharing the surface OBN nodal survey airgun sources. This is an important experiment for the field in the future so that the need to halt insitu field production for 4D time lapse monitoring will not be required if the S/N is acceptable by using this method. This permanent installation of fiber optic cables has become our ears on wells, not only for 3D DAS VSP but for proactive monitoring of the field, ensuring optimum production performance throughout the life of the field.","PeriodicalId":325107,"journal":{"name":"Day 1 Mon, September 30, 2019","volume":"21 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121507995","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Viscoelastic Characterization Effect of High-Viscosity Friction Reducers and Proppant Transport Performance in High-TDS Environment","authors":"M. B. Geri, Abdulaziz Ellafi, R. Flori, J. Noles, Sangjoon Kim","doi":"10.2118/196014-ms","DOIUrl":"https://doi.org/10.2118/196014-ms","url":null,"abstract":"\u0000 Viscoelastic property of high-viscosity friction reducers (HVFRs) was developed as an alternative fracturing fluid system because of advantages such as the ability to transport particles, higher fracture conductivity, and potential lower cost due to fewer chemicals and equipment on location. However, concerns remain about using HVFRs to transport proppant in DI water and harsh brine solution (e.g. 2wt% KCl and 10 lbs. brine). The primary objective of this study is to investigate the viscoelastic property that can help to understand the true proppant transporting capacity of fracturing fluids in high-TDS environment.\u0000 To address the evaluation performance of HVFRs, a comprehensive review of numerous papers associated to viscoelastic property of hydraulic fracturing fluids were investigated and summarized. This paper also provides a full comparison study of viscosity and elastic modulus between HVFRs and among fracturing fluids such as xanthan, polyacrylamide-based emulsion polymer, and guar. Moreover, viscosity profiles and elastic modulus were conducted at different temperatures. Better proppant transportation effect though higher viscosity through Stoke's law and the effect on proppant transportation from elastic modulus comparison were also investigated. Finally, HVFR Conductivity test and successful field test result were explained.\u0000 The results of the experimental work show that viscoelastic property HVFRs provides good behavior to transport proppant. Viscosity profile decreased slightly as the temperature increased from 75 to 150 when the DI water was used. While using 10 lbs. Brine the viscosity was reduced by 33%. The longer polymer chains of HVFR indicated better elastic modulus in DI water. The elastic modulus also indicated that the highest values at frequency 4.5 Hz from each amplitude, and lower values as amplitude was increased. Although high molecular weight HVFRs were utilized on the conductivity test, the results observed that the regained permeability was up to 110%. Finally, the promising results from the case study showed that using HVFRs could be performed economically and efficiently for the purpose of proppant transportation and pressure reduction in high TDS fluids.","PeriodicalId":325107,"journal":{"name":"Day 1 Mon, September 30, 2019","volume":"142 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-09-23","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115213930","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}