Day 4 Thu, June 06, 2019最新文献

{"title":"Experimental and Numerical Evaluation of Spontaneous Imbibition Processes in Unfractured and Fractured Carbonate Cores with Stress-Induced Apertures","authors":"Odilla Vilhena, A. Farzaneh, Jackson Andreas Pola, R. March, A. Sisson, M. Sohrabi","doi":"10.2118/195452-MS","DOIUrl":"https://doi.org/10.2118/195452-MS","url":null,"abstract":"\u0000 Spontaneous imbibition (SI) experiments in fractured and unfractured Indiana limestone cores were performed to evaluate the impact of fractures in oil recovery. Numerical simulations were run to reproduce the experimental setting and history match fracture and matrix properties. Tracer tests were carried out to investigate the effect of changing stresses in the hydraulic fracture conductivity. The pore space and connected pores in the fractured plug were analysed via Micro-CT scan and thin petrography analysis was carried out to observe the matrix heterogeneity of the samples. Relative permeability, capillary pressure and fracture properties were estimated numerically for Indiana limestone carbonate rocks to match the SI curves measured at a temperature of 58.7° C. The investigation shows that the fractured core has suffered a deformation under stress conditions impacting the initial values of fracture aperture and permeability. This deformation has led to decreased flow rates in the fracture and oil trapping in the fracture channel. At the field scale, this phenomenon could lead to decreased oil recovery in the first days of production.","PeriodicalId":103248,"journal":{"name":"Day 4 Thu, June 06, 2019","volume":"47 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-06-03","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115645291","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":"Evaluation of CO2-EOR Performance and Storage Mechanisms in an Active Partially Depleted Oil Reservoir","authors":"E. Kutsienyo, W. Ampomah, Qian Sun, R. Balch, Junyu You, W. N. Aggrey, M. Cather","doi":"10.2118/195534-MS","DOIUrl":"https://doi.org/10.2118/195534-MS","url":null,"abstract":"\u0000 This paper presents field-scale numerical simulations of CO2 injection activities in the Pennsylvanian Upper Morrow sandstone reservoir, usually termed the Morrow B sandstone, in the Farnsworth Unit (FWU) of Ochiltree County, Texas. The CO2 sequestration mechanisms examined in the study include structural-stratigraphic, residual, solubility and mineral trapping. The reactive transport modelling incorporated in the study evaluates the field's potential for long-term CO2 sequestration and predicts the CO2 injection effects on the Morrow B pore fluid composition, mineralogy, porosity, and permeability.\u0000 The dynamic CO2 sequestration model was built from an upscaled geocellular model for the Morrow B. This model incorporated geological, geophysical, and engineering data including well logs, core, 3D surface seismic and fluid analysis. We calibrated the model with active CO2-WAG miscible flood data by adjusting control parameters such as reservoir rock properties and Corey exponents to incorporate potential changes in wettability. The history-matched model was then used to evaluate the feasibility and mechanisms for CO2 sequestration. We used the maximum residual phase saturations to estimate the effect of gas trapped due to hysteresis. The coupled approach which involves the aqueous phase solubility and geochemical reactions were modelled prior to import into the compositional simulation model. The viscosities of the liquid-vapor phases were modeled based on the Jossi-Stiel-Thodos Correlation. This correlation depended on the mixture density calculated by the equation of state. The gas solubility coefficients for the aqueous phase were estimated using Henry's law for various components as function of pressure, temperature, and salinity. The characteristic intra-aqueous and mineral dissolution/precipitation reactions were assimilated numerically as chemical equilibrium and rate-dependent reactions respectively. Multiple scenarios were performed to evaluate the effects and potentials of the CO2 sequestrated within the Morrow formation. Additional scenarios that involve shut-in of wells were performed and the reservoir monitored for over 150 years to understand possible dissolution/precipitation of minerals. Changes in permeability as a function of changes in porosity caused by mineral precipitation/dissolution were calibrated to the laboratory chemo-mechanical responses.\u0000 This confirms the CO2 injection in the morrow B will alter petrophysical properties, such as permeability and porosity in short-term due to the dissolution of calcite. However, further investigation for the long-term effects needs to be conducted. Moreover, the following significant observations are extracted from the result of this study: oil recovery, total volume of CO2 due to multiple trapping mechanisms, effect of salinity, the timescale-view of the dissolution/precipitation evolution in the Morrow B sandstone.\u0000 Experiences gained from this study offers valuable visions regardi","PeriodicalId":103248,"journal":{"name":"Day 4 Thu, June 06, 2019","volume":"101 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-06-03","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114892112","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":"Alkali Co-Solvent Polymer Flooding of High TAN Number Oil: Using Phase Experiments, Micro-Models and Corefloods for Injection Agent Selection","authors":"B. Schumi, T. Clemens, J. Wegner, L. Ganzer, A. Kaiser, R. Hincapie, Verena Leitenmüller","doi":"10.2118/195504-MS","DOIUrl":"https://doi.org/10.2118/195504-MS","url":null,"abstract":"\u0000 Chemical Enhanced Oil Recovery leads to substantial incremental costs over waterflooding of oil reservoirs. Reservoirs containing oil with a high Total Acid Number (TAN) could be produced by injection of alkali. Alkali might lead to generation of soaps and emulsify the oil. However, the generated emulsions are not always stable.\u0000 Phase experiments are used to determine the initial amount of emulsions generated and their stability if measured over time. Based on the phase experiments, the minimum concentration of alkali can be determined and the concentration of alkali above which no significant increase in formation of initial emulsions is observed.\u0000 Micro-model experiments are performed to investigate the effects on pore scale. For injection of alkali into high TAN number oils, mobilization of residual oil after waterflooding is seen. The oil mobilization is due to breaking-up of oil ganglia or movement of elongated ganglia through the porous medium. As the oil is depleting in surface active components, residual oil saturation is left behind either as isolated ganglia or in down-gradient of grains.\u0000 Simultaneous injection of alkali and polymers leads to higher incremental oil production in the micro-models owing to larger pressure drops over the oil ganglia and more effective mobilization accordingly.\u0000 Core flood tests confirm the micro-model experiments and additional data are derived from these tests. Alkali co-solvent polymer injection leads to the highest incremental oil recovery of the chemical agents which is difficult to differentiate in micro-model experiments. The polymer adsorption is substantially reduced if alkali is injected with polymers compared with polymer injection only. The reason is the effect of the pH on the polymers. As in the micro-models, the incremental oil recovery is also higher for alkali polymer injection than with alkali injection only.\u0000 To evaluate the incremental operating costs of the chemical agents, Equivalent Utility Factors (EqUF) are calculated. The EqUF takes the costs of the various chemicals into account. The lowest EqUF and hence lowest chemical incremental OPEX are incurred by injection of Na2CO3, however, the highest incremental recovery factor is seen with alkali co-solvent polymer injection. It should be noted that the incremental oil recovery owing to macroscopic sweep efficiency improvement by polymer needs to be taken into account to assess the efficiency of the chemical agents.","PeriodicalId":103248,"journal":{"name":"Day 4 Thu, June 06, 2019","volume":"28 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-06-03","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122302378","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":"Geomechanical Model of a Gas Field for Seismic Risk Analysis","authors":"C. Berentsen, C. D. Pater, F. Nieuwland","doi":"10.2118/195442-MS","DOIUrl":"https://doi.org/10.2118/195442-MS","url":null,"abstract":"\u0000 The Slootdorp field has a complex structure with most reserves in Rotliegend sandstone, which is communicating with gas bearing Zechstein carbonates. The Rotliegend reservoir is bounded by a large fault, which might become seismogenic during depletion. A 3D geomechanical model was built, based on the faults and horizons in the geological model. Both the Rotliegend and Zechstein reservoirs were included in the model. The model was populated with geomechanical properties derived from logs, LOT's (leak off tests) and regional data on the stress field. Also, overburden properties from previous studies on nearby fields were used.\u0000 The pressure input was obtained from reservoir simulation. It is important to include the water leg pressure in the pressure input since the Rotliegend gas reservoir is in contact with an active aquifer. Pressure reduction drives the compaction of the reservoir, which induces stresses on the faults causing slippage. Since the water is quite incompressible, a large pressure reduction in the water leg may be caused temporarily by a rising gas water contact.\u0000 It turned out that slippage is not expected at the lowest gas pressure using a conservative estimate of the critical friction coefficient on the fault of 0.55. Sensitivity analysis on the most important input parameters was performed with a range that can be expected for such a field. The result was that the maximum critical stress ratio could range between 0.46 and 0.53 for the expected uncertainty of input parameters. The geomechanical modeling shows that an active aquifer has a dominant, mitigating effect on seismic risk, which can explain why many reservoirs show no seismicity in the Netherlands, although other effects could also play a role.","PeriodicalId":103248,"journal":{"name":"Day 4 Thu, June 06, 2019","volume":"54 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-06-03","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133013796","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":"Slug Flow Monitoring in Pipes Using a Novel Non-Intrusive Optical Infrared Sensing Technology","authors":"K. Sarkodie, Andrew Fergusson-Rees, N. Makwashi, P. Diaz","doi":"10.2118/195449-MS","DOIUrl":"https://doi.org/10.2118/195449-MS","url":null,"abstract":"\u0000 The application of real - time monitoring technologies presents a means to harnessing proactive or reactive controls in minimizing severity effects of slugging in the production system. This paper presents the development of a non-intrusive optical infrared sensing (NIOIRS) setup, for slug monitoring in pipes. The flow characteristics monitored were the development of slug flows and average phase fractions of gas and liquid in a vertical test section (0.018m by 1m) for superficial velocities of 0-0.131 m/s for water and 0 – 0.216 m/s for air. The measurement principle was based on the disparities in refractive indices of each phase in the sensing area. The sensing component of the sensor consisted of two pairs of IR emitters and photodiodes operated at wavelengths of 880 nm specifications. A circuit, for signal conditioning, amplification and data acquisition was set up to convert infrared light detected into voltage signals. Development of slug flow regimes was monitored from signal distributions binned under reference voltages. The transitions from bubble to slug flow, were observed at 10 percent count of the signal distributions around typical sensor response for air. Validation from photos showed good agreements with the sensor response. A single peaked distribution around the response for water indicated bubble flow regimes, with the development of two peaks indicated increasing gas slugs for increasing superficial gas velocities compared to liquid slug in the pipe. Phase fraction results were interpreted from a derived calibration models, which were based on the average observed response and reference responses of water and air over time. This model was compared with swell level changes, photographs and homogenous and drift flux correlation with agreement within maximum error bands +/− 0.5 % based on the swell level method and +/− 0.3% based on photographs. The Real-time application was carried out via the execution of an algorithm which incorporated the calibration information from the NIOIRS. The derived signals were processed and analyzed onto a display to identify slug flow development and phase fractions in real-time. A cheap and accurate sensing setup has been developed with the potential of real time monitoring of flow regimes and phase fraction determination.","PeriodicalId":103248,"journal":{"name":"Day 4 Thu, June 06, 2019","volume":"16 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-06-03","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124100962","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":"Preston New Road: The Role of Geomechanics in Successful Drilling of the UK's First Horizontal Shale Gas Well","authors":"H. Clarke, H. Soroush, T. Wood","doi":"10.2118/195563-MS","DOIUrl":"https://doi.org/10.2118/195563-MS","url":null,"abstract":"\u0000 The Bowland Basin in Northern England contains a thick shale gas section (>5,000 ft) estimated to hold over 1300 TCF of total original gas in place of shale gas resource. In 2017, Cuadrilla Resources drilled a S-shaped pilot well, Preston New Road-1 (PNR-1), located in Lancashire, NW England. The plan was to drill, core, and log the Bowland Shale sequence with the primary objective to select the optimum landing depth for a subsequent side-tracked horizontal section (PNR-1z) of up to 3,280 ft length to be completed for multi-stage hydraulic fracturing. Another multi-stage horizontal well, PNR2, was also planned to be drilled afterward targeting a different stratigraphic horizon. Three vertical wells (PH-1, GH-1 and BS-1) were previously drilled in the Bowland Basin to a depth of 8,860-10,500 ft. Delays were encountered in the drilling of these wells due to multiple borehole stability problems. Specifically, in GH-1, the well required a side-track to reach the target depth. With the plan to drill four horizontal wells at Preston New Road, the first horizontal wells ever to be drilling in the Bowland shale, a rigorous geomechanical study was required to provide valuable insights for optimisation of the drilling programme.\u0000 A pre-drill geomechanical model was developed for the PNR-1 pilot well using advanced interpretation of available data and the gained experiences from the offset wells. A comprehensive pore pressure interpretation showed that Bowland shale is significantly over-pressured (0.69 psi/ft). The model was backed up by the observed splintery cuttings and gas shows in offset wells. It was concluded that this abnormal pore pressure combined with a tectonic strike-slip stress regime (with large horizontal stress anisotropy) and intrinsic anisotropic shale properties were the primary causative factors for drilling incidents. As a result of this study, the PNR-1 was successfully drilled and completed with minimal borehole stability problems despite the presence of narrow operating mud weight window in several stratigraphic intervals. The data acquisition program conducted included 114m of core from Upper and Lower Bowland shales, with the required logs for updating the geomechanical model. A comprehensive rock mechanics testing program was designed and conducted which resulted in better characterizing the anisotropic elastic properties and strength parameters of the Bowland Shale. This information was used to update the geomechanical model and aid the optimum landing decision depth of 2,180m for PNR-1z. A successful XLOT prior to drilling the 6\" lateral section provided valuable data for further calibration of the stress model. The updated model was then used to develop safe operating mud weight window for PNR-1z, which helped drilling of the horizontal section to the TD at 11,233 ft MD (7,457 ft TVD) with no notable drilling problems.\u0000 This paper presents a summary of the geomechanical work performed for successful drilling and hydraulic f","PeriodicalId":103248,"journal":{"name":"Day 4 Thu, June 06, 2019","volume":"26 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-06-03","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127464340","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":"Effects of Permeability and Wettability on CO2 Dissolution and Convection at Realistic Saline Reservoir Conditions: A Visualization Study","authors":"W. Amarasinghe, I. Fjelde, J. Rydland, Ying Guo","doi":"10.2118/195469-MS","DOIUrl":"https://doi.org/10.2118/195469-MS","url":null,"abstract":"\u0000 When CO2 is injected to aquifers, CO2 will be dissolved into the water phase and react with rock minerals. The CO2 dissolution into the water phase initiated by the diffusion, will increase the density of the water- phase and thereby accelerate convective flow of CO2. The objective of the presented work was to study the effects of permeability and wettability of porous media by visual investigation of mixing of supercritical CO2 (sCO2) with water by convectional flow at realistic reservoir conditions (pressure and temperature). This required construction of a high-pressure transparent 2D-cell that allows visualization of CO2 transport, and development of experimental procedures.\u0000 To develop the high-pressure Hele-Shaw 2D-cell, stress/strain calculations and simulations were carried out to select the best building materials for realistic working pressure and temperature and required dimensions to study convection. Porous media was prepared by glass beads of different sizes giving different permeability and wettability. The experiments were carried out at 100 bars and 50 °C using deionized water solution with Bromothymol blue (BTB) as pH indicator.\u0000 In the constructed Hele-Shaw 2D-cell, the cell volume was formed by two glass plates separated by an adjustable spacer. The cell thickness was 5.0 mm in the present study. The high-pressure 2D-cell has made it possible to investigate CO2-dissolution and mixing with water at pressures and temperatures realistic for CO2-storage reservoirs.\u0000 CO2 mixing and finger development in the water phase without the presence of porous media, was an instantaneous process. The rate for CO2 dissolution and mixing with water was found to increase with increasing permeability for water-wet porous media. The CO2 dissolution pattern was found to depend on the permeability. Fingering of CO2 rich high-density water was observed with the high permeable porous media. Piston-like displacement was observed in lower permeable porous media. No significant effect of wettability was observed in the high-pressure 2D cell experiments. After experiments, it was confirmed that the wettability of the oil-wet particles was changed during the CO2 dissolution experiments.","PeriodicalId":103248,"journal":{"name":"Day 4 Thu, June 06, 2019","volume":"15 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-06-03","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129039465","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":"Production Interference of Hydraulically Fractured Hydrocarbon Wells: New Tools for Optimization of Productivity and Economic Performance of Parent and Child Wells","authors":"R. Weijermars, A. Khanal","doi":"10.2118/195544-MS","DOIUrl":"https://doi.org/10.2118/195544-MS","url":null,"abstract":"\u0000 The present study provides a comprehensive set of new analytical expressions to help understand and quantify well interference due to competition for flow space between the hydraulic fractures of parent and child wells. Determination of the optimum fracture spacing is a key factor to improve the economic performance of unconventional oil and gas resources developed with multi-well pads. Analytical and numerical model results are combined in our study to identify, analyze, and visualize the streamline patterns near hydraulic fractures, using physical parameters that control the flow process, such as matrix permeability, hydraulic fracture dimensions and assuming infinite fracture conductivity. The algorithms provided can quantify the effect of changes in fracture spacing on the production performance of both parent and child wells. All results are based on benchmarked analytical methods which allow for fast computation, making use of Excel-based spreadsheets and Matlab-coded scripts. Such practical tools can support petroleum engineers in the planning of field development operations. The theory is presented with examples of its practical application using field data from parent and child wells in the Eagle Ford shale (Brazos County, East Texas). Based on our improved understanding of the mechanism and intensity of production interference, the fracture spacing (this study) and inter-well spacing (companion study) of multi-fractured horizontal laterals can be optimized to effectively stimulate the reservoir volume to increase the overall recovery factor and improve the economic performance of unconventional oil and gas properties.","PeriodicalId":103248,"journal":{"name":"Day 4 Thu, June 06, 2019","volume":"66 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-06-03","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"126279693","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":"Foam Assisted Gas Lift: The Impact of Different Surfactant Delivery Methods on Oil Well Performance","authors":"A. Martins, Marco Marino, M. Kerem, M. Guzmán","doi":"10.2118/195462-MS","DOIUrl":"https://doi.org/10.2118/195462-MS","url":null,"abstract":"\u0000 This paper presents the first comparison between two different injection methods for foam assisted gas lift. Useful information for operators and technology developers are also provided concerning chemical selection, testing, and deployment of this hybrid artificial lift technology in the field.\u0000 The trials have been conducted in a gas lifted oil well with severe slugging and water cut above 50% (selection criteria as per SPE-184217-MS). The surfactant was delivered through a dedicated capillary injection string during the first trial, and the effects of surfactant concentration and depth of injection were evaluated. During the second trial, the surfactant was injected into the gas lift stream at the surface. Different surfactants were utilised for both trials based on stability concerns and method of injection.\u0000 Both trialled injection methods successfully stabilized the well flow, terminating severe slugging while increasing the drawdown and delivering an increase in gross production of circa 200%. These results, together with the downhole pressure data collected during the first trial, confirm that the surfactant starts foaming only at the depth where the lift gas enters the tubing. Injecting surfactant into the lift gas stream required higher concentrations than using a dedicated injection string, difference attributable to the slightly different chemistry, but even at those higher concentrations an anti-foamer injection was not required.\u0000 Concerning the response time, the well responded in 30 to 60 minutes with capillary string injection, while 6 to 12 hours were required for injection into the lift gas stream. This suggests that the surfactant probably moves slowly down on the annulus walls as a liquid film rather than travelling in droplets dispersed in the gas phase. Based on the outcome of the two trials, it is concluded that the injection via the lift gas stream is as effective as capillary string injection, at a fraction of the initial costs, with lower maintenance requirements, while still allowing access to the well.","PeriodicalId":103248,"journal":{"name":"Day 4 Thu, June 06, 2019","volume":"44 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-06-03","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121244556","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 Semi-Analytical Poroelastic Solution to Evaluate the Stability of a Borehole Drilled Through a Porous Medium Saturated with Two Immiscible Fluids","authors":"Jiajia Gao, H. Lau, Jin Sun","doi":"10.2118/195515-MS","DOIUrl":"https://doi.org/10.2118/195515-MS","url":null,"abstract":"\u0000 Conventional drilling design tends to inaccurately predict the mud density needed for borehole stability because it assumes that the porous medium is fully saturated with a single fluid while in actuality it may have two or more fluids.\u0000 This paper provides a new semi-analytical poroelastic solution for the case of an inclined borehole subjected to non-hydrostatic stresses in a porous medium saturated with two immiscible fluids, namely, water and gas. The new solution is obtained under plane strain condition. The wellbore loading is decomposed into axisymmetric and deviatoric cases. The time-dependent field variables are obtained by performing the inversion of the Laplace transforms. Based on the expansion of Laplace transform solution, we derive the unsaturated poroelastic asymptotic solutions for early times and for a small radial distance from an inclined wellbore. The model is verified by analytical solutions for the limiting case of a formation saturated with a single fluid. The impact of the unsaturated poroelastic effect on pore pressure, stresses and borehole stability is investigated.\u0000 Our results show that the excess pore pressure due to the poroelastic effect is generally higher for the saturated case (water) than the unsaturated case due to the large difference between the compressibility of fluid phases (water and gas). The time-dependency of the poroelastic effect causes the safe mud pressure window of both the unsaturated and saturated cases to narrow and approach the long-time poroelastic one with increasing time. The safe mud pressure window narrows with increasing initial gas saturation. The commonly used assumption that the formation is fully saturated by one fluid (such as water) tends to be conservative in predicting the mud density required for borehole stability.\u0000 This new semi-analytical poroelastic solution enables the drilling engineer to more accurately estimate the time-dependent stresses and the pore pressure around a borehole, thus allowing him to design the mud weight to ensure borehole stability.","PeriodicalId":103248,"journal":{"name":"Day 4 Thu, June 06, 2019","volume":"235 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-06-03","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116429072","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}