Day 1 Mon, September 30, 2019最新文献

{"title":"Optimization of Multi-Fractured Horizontal Well Completion: A Montney Example","authors":"B. Haghshenas, F. Qanbari","doi":"10.2118/196012-ms","DOIUrl":"https://doi.org/10.2118/196012-ms","url":null,"abstract":"\u0000 After a successful decade of exploration and development activities in major tight/shale reservoirs, the industy now has access to incredible sets of data, modeling tools, and technologies for multi-fractured horizontal well (MFHW) completion. A review of the available data and models shows that performance of a MFHW is governed by hydraulic facture properties (dimension, conductivity, and distribution) and reservoir fluid and rock characteristics (reservoir fluid properties, and rock storage and flow capacities). Workflows are required to link the characterization attempts (reservoir and MFHW), learnings from completion expriments, modeling approaches (reservoir and fracture modeing) and pettern recognition exercises (relationship between well performance metrics and the governing parameters).\u0000 In the current study, an interative workflow is proposed for design and optimization of MFHW completion based on a mixed-method approach combining three major paradigms: experiments, modeling, and data science. Each cycle of the workflow starts with data gathering and characterization of reservoir fluid and rock, followed by reservoir and fracture modeling, statistical analysis, updated design, economc analysis, and ends with implementation, monitoting and data analysis. The first cycle of the workflow is the most time-consuming and tedious one which requires a great deal of discussions and instructions.\u0000 The proposed workflow is tried on a population of Montney gas condensate wells. Rate-transient analysis (RTA) and numerical reservoir modeling were applied to a group of 16 Monteny gas condensate wells with detailed daily production and flowing pressure data. Further, a simplified RTA-based approach and statistical analysis were applied to more than 90 Montney gas condensate wells (from the same region) with publically available production data.\u0000 A new design with optimized completion paramteres is obtained from the results of RTA, numerical reservoir modeling, statistical and ecnomic analyses. The new design is applied to six new wells in the same area. The average performance of the new wells is reasonably close to the predicted performance by the proposed workflow. The workflow is believed to optimize the well performance, save the operator millions of dollars through optimization, and give the management and technical teams confidence in the next phase of corporate planning.","PeriodicalId":325107,"journal":{"name":"Day 1 Mon, September 30, 2019","volume":"4 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":"122238174","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":"Robustness of Novel Low-Tension Gas LTG Floods in High Salinity and High Temperature Reservoirs","authors":"N. Nguyen, G. Ren, K. Mateen, Kun Ma, Haishan Luo, V. Neillo, Q. Nguyen","doi":"10.2118/195892-ms","DOIUrl":"https://doi.org/10.2118/195892-ms","url":null,"abstract":"\u0000 Low-Tension Gas (LTG) has emerged as a novel enhanced oil recovery injection strategy, employing foam in place of polymer to displace the oil bank created with the help of ultra-low-IFT (ULIFT). In our prior work, the process was successfully employed, both in sandstones and carbonates, to achieve attractive oil recoveries with relatively low surfactant retention. However, earlier experiments were carried out at high flow rates in relatively high permeability cores. To improve the robustness of this novel injection scheme, it is necessary to examine it under wider practical environments. Therefore, in this work, experiments are conducted in carbonate and sandstone cores, at lower injection rates and rock permeabilities, to determine whether the foam could provide the necessary mobility control with this novel EOR technique. Initially, a lower flow rate (1 ft/D) experiment is conducted in relatively high permeability (388 md) sandstone core to compare it with the earlier results under a higher injection rate (4 ft/D). Subsequently, even further reduced injection rate (0.5 ft/D) is employed in a sandstone core with one order of magnitude lower permeability (36 md). Two other corefloods with Estaillades limestone (166 md) and Richmont (7 md) are carried out to extend the comparison to carbonate rocks. Surfactant retentions are determined. It is found that four-times-lower injection rate (1ft/D) just slightly delayed oil production, and achieved comparably high oil recovery (87%), indicating a good mobility control. Proportionally reduced pressure drop during slug injection implies similar total fluid mobility. Accordingly, salinity propagation examined from effluents shows slight delays. Even with ten-times-lower permeability sandstone (36 md) at a lower total injection rate (0.5 ft/D), comparable oil recovery (84%) and salinity propagation are found, despite of much lower foam strength. With an intermediate-permeability Estaillades limestone (166 md), compared to high permeability sandstone, oil production is delayed, but comparable eventual oil recovery (88%) is obtained. The delay could be due to higher surfactant retention (0.301 mg/g). The delayed effluent salinity propagation is noticeable, which may be caused by increased total fluid mobility. Finally, extremely low permeability Richmont (7 md) indeed adversely impacts the oil recovery (~58%) and the salinity propagation. This could be attributed to higher surfactant retention and/or decreased foam stability due to oil-wet rock surface. The works here test the robustness of the LTG process in more practical reservoir conditions and have widened its applicability. Demonstration of its feasibility in low-permeability reservoirs, where use of polymer is not currently feasible, will greatly promote the testing and deployment of this technology in the future.","PeriodicalId":325107,"journal":{"name":"Day 1 Mon, September 30, 2019","volume":"20 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":"127183790","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":"Potential of Associative Polymers as Mobility Control Agents in Low Permeability Carbonates","authors":"P. Ghosh, A. Zepeda, Gildardo Bernal, K. Mohanty","doi":"10.2118/195955-ms","DOIUrl":"https://doi.org/10.2118/195955-ms","url":null,"abstract":"\u0000 Waterflood in low permeability carbonate reservoirs (<50 mD) leaves behind a substantial amount of oil due to capillary trapping and poor sweep. Addition of polymer to the injected water increases the viscosity of the aqueous phase and decreases the mobility ratio, thus, improving the sweep efficiency and oil production from the tight formations. Performance of current synthetic EOR polymers is limited by salinity, temperature and injectivity issues in low permeability formations. Mechanical shear degradation can be applied to high molecular weight synthetic polymers to improve the injectivitiy; but makes the process less economical due to significant viscosity loss and consequent increase in polymer dosage. Recently, a different class of polymer has been developed called \"hydrophobically modified associative polymers (AP)\". The primary goal of this work is to investigate the performance of associative polymers in low permeability carbonate reservoirs. We compare the performance of associative polymers with that of conventional HPAM polymers in low permeability formations. A low molecular weight associative polymer was investigated as part of this study. A detailed study of polymer rheology and the effect of salinity at the reservoir temperature (60 °C) was performed. Additional experiments were performed in bulk and porous media to investigate the synergy of associative polymers with hydrophilic surfactant blends at different brine salinities. Single phase polymer flow experiments were performed in outcrop Edwards Yellow and Indiana limestone cores of low permeability to determine the optimum polymer concentration to achieve the desired in-situ resistance factor (or apparent viscosity). Similar experiments were performed with HPAM polymer for a comparative study. Results showed successful transport of this associative polymer in low permeability formations after a small degree of shear degradation. The resistance factors for the associative polymer were higher than those for HPAM. Shear degraded polymers showed significant improvement in polymer transport in lower permeability cores with reduction in RRF.","PeriodicalId":325107,"journal":{"name":"Day 1 Mon, September 30, 2019","volume":"13 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":"128766202","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":"Innovative Artificial Intelligence Approach in Vaca Muerta Shale Oil Wells for Real Time Optimization","authors":"Adriana Romero Quishpe, Katherine Silva Alonso, J. Claramunt, J. L. Barros, P. Bizzotto, E. Ferrigno, G. Martinez","doi":"10.2118/195940-ms","DOIUrl":"https://doi.org/10.2118/195940-ms","url":null,"abstract":"\u0000 A well is in natural flowing state when its bottom-hole pressure is enough to produce to the surface. Natural flowing well’s production is regulated by using surface restrictions to regulate the production rate in such a way that the overall well performance is a function of several variables. Examples of these variables are tubing size, choke size, wellhead pressure, flow line size, and perforation density. This implies that changing any of these variables will modify well performance. One of the techniques for the analysis of production performsnce is studying the wellhead pressure declination, since, in critical flow conditions, flow is a function of wellhead pressure. From wellhead pressure trends you can identify the behavior of each well and determine some issues, such as: choke erosion due to sand production, choke o tubing paraffin plugging or choke obstruction. In order to achieve an effective real-time monitoring of this type of wells, and in this way reduce the production losses, the challenge was to create online tools that could detect those mentioned issues.\u0000 The present work performs the analysis of wellhead pressure curves using data science, with the purpose of predicting real time anomalies that could occur for timely correction. The data correspond to 130 flowing wells from the Loma Campana Field. The study began with a filtering process of the pressure curve, with two specific objectives: first, eliminate atypical values from the time series, and second, smooth the curve in such a way that future predictions can be performed. Next, the Prophet methodology was applied with the purpose of predicting values of the curve. This is based on historicsl values of the time series to predict future values; the trend characteristic of the curve was used to apply this methodology. Then, to identify the anomaly a model was designed based on the declination of the curve. The pressure declination curve is a descending exponential function, so the first and second derivatives indicate the trend (ascending - descending) and curvature (concave or convex) of it. Once these values are available, they are classified according to the anomaly: paraffin, encrustation or obstruction. Finally, the model is being tested in the Loma Campana control room, delivering a probability of occurrence of any anomalies every hour.","PeriodicalId":325107,"journal":{"name":"Day 1 Mon, September 30, 2019","volume":"20 2 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":"128058184","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":"Long-Term Productivity Comparison of Gel and Water Fracture Stimulation in Marcellus Shale Play","authors":"M. A. Al-Alwani, L. Britt, S. Dunn-Norman, H. Alkinani, A. T. Al-Hameedi, A. Al-Attar","doi":"10.2118/195990-ms","DOIUrl":"https://doi.org/10.2118/195990-ms","url":null,"abstract":"\u0000 The goal of any hydraulic fracturing stimulation is to design and execute the appropriate treatment that is best suited for the stimulated reservoir. Selecting the best treatment must achieve the desired fracture geometry to maximize long-term well productivity and reserve recovery. The main objective of this study is to conduct detailed short and long-term production and well-to-well comparisons of the different types of fracture stimulation fluids in the Marcellus Shale play.\u0000 A database of more than 4,000 horizontal, stimulated Marcellus wells was constructed for this study. The wells were divided into four groups according to the type of treating fluid: water, gel, cross-linked, and hybrid fracs. Chemical data from FracFocus were gathered and processed then combined with completion and production data to investigate the gas short and long-term production. Detailed monthly production data for the studied wells were captured from DrillingInfo database and utilized in this study.\u0000 This paper reports and compares the Marcellus gas initial production, the gas cumulative production at the end of the first month, first 6 months, first year, 2 years, and 5 years, according to the type of hydraulic fracturing fluid used in primary stimulation. The work provides insights into Marcellus well performance as a function of stimulation parameters such as the volume of stimulation fluid and the amount of pumped proppants. The impact of perforated lateral length is taken into consideration and used to normalize production and stimulation parameters. The study shows that water fracturing fluids outperformed the other types of hydraulic fracturing fluids.\u0000 This paper introduces several data processing workflows that serve as a reference for individuals who are interested in extracting and processing data from the FracFocus database. It also documents the occurrence in hydraulic fracturing fluid types and measures the effects of the fracturing fluid volume and total proppant pumped on the initial and cumulative production.","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":"126344750","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":"Tunable Friction Reducer Improves Operational Efficiency and Increases Production in the Eagle Ford","authors":"J. Luster, Christine De Sario, S. Khan, J. Long","doi":"10.2118/196105-ms","DOIUrl":"https://doi.org/10.2118/196105-ms","url":null,"abstract":"\u0000 This study will demonstrate a comparison of completion fluid designs in operations and production across several pads in Gonzales and Lavaca counties in the Eagle Ford Basin. The use of tunable friction reducers (FRs) significantly improves completion efficiency and production. The paper also illustrates how tunable FRs provide greater versatility at the wellhead by replacing multiple fracturing fluid systems such as conventional friction reducer and linear gel with a single additive.\u0000 When conventional FRs prove inadequate in slickwater designs, subsequent HVFR and linear gel designs are utilized. This study demonstrates that tunable FRs provide the flexibility to be run at lower concentrations as an effective and efficient friction reducer. Should the slickwater treatment be insufficient, the FR concentration can easily be increased to achieve improved results for pressure reduction and sand placement while minimizing chemical additives and equipment on location. In addition, this tunable FR is engineered with breakable linkages that minimize formation damage to help improving production.\u0000 Tunable FRs can be run at less concentration compared to conventional FRs while delivering the same friction reduction as slickwater. Increasing the concentration produces a higher viscosity similar to that seen in linear gel. This flexibility is achieved with less equipment and additives and can be executed on- the-fly while pumping. This design has enabled an operator in the Eagle Ford to complete more stages with less shutdowns and screenouts. Eliminating equipment and extra additives simiplified logistics, reduced the footprint and equipment-related non-produtive time (NPT). Overall, production results taken over the first 12 months show that wells completed with the tunable FR had noticeably superior performance in cumulative production, which is normalized by lateral length. These improvements can be attributed to the proppant transport capabilities and the breakability of the tunable FR, which minimizes residue left in the formation and, in turn, provides greater regain conductivity.\u0000 Additional benefits include simplified delivery and smaller jobsite footprint requirements, which lead to significant cost savings. The tunability of the FR allows it to be administered on the fly while pumping, giving design change flexibility, enhancing overall operational efficiency. Since there is no need of hydration unit or dry-on-the-fly (DOTF) unit used for hybrid linear gel design, fewer NPT hours due to equipment breakdown was seen on location.","PeriodicalId":325107,"journal":{"name":"Day 1 Mon, September 30, 2019","volume":"52 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":"122595646","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":"Analyzing Fractures Using Time-Lapse Electric Potential Data","authors":"Jason C. Hu, R. Horne","doi":"10.2118/196144-ms","DOIUrl":"https://doi.org/10.2118/196144-ms","url":null,"abstract":"\u0000 Characterizing the fractures is an important task to improve the understanding and utilization of hydraulic fracturing. As an approach to augment and improve on the existing methods, time-lapse electric potential measurements could be used to characterize subsurface features. In this study we investigated the characterization of fracture length and fracture density by using time-lapse electric potential data. A new borehole ERT (electric resistivity tomography) method designed specifically for hydraulic fracture characterization is proposed to better capture reservoir dynamics during hydraulic fracturing. This method uses high resolution electric potential data by implementing electrodes in or near boreholes and monitor electric potential distribution near the horizontal fracture zone. The time-lapse electric potential data generated by this tool were simulated and subsequently used to analyze fracture characteristics. Inverse analysis was then performed on the electric potential data to estimate fracture length and fracture density. Last, we performed sensitivity analysis to examine the robustness of the estimates in nonideal environments. The results of this work show that time-lapse electric potential data are capable of capturing flow dynamics during the fracturing process. Using the proposed borehole ERT method we successfully estimated the true fracture length and true fracture density of a constructed fracture model. We were able to determine the best locations in the constructed reservoir to place the electrodes, and through sensitivity analysis we found the maximum noise level of the electric potential data that can still allow the proposed method to make robust fracture length and fracture density estimates.\u0000 Our proposed method offers a new approach to make robust estimates of fracture length and fracture density. Electric potential data have been used mostly for well logging in the past. This study demonstrates a novel way of using electric potential data in unconventional development and opens possibilities for more applications such as production monitoring.","PeriodicalId":325107,"journal":{"name":"Day 1 Mon, September 30, 2019","volume":"45 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":"122679511","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":"New Acid-Tunneling Insights from Full-Scale Water- and Acid-Jetting Tests","authors":"S. Livescu, D. McDuff, Bruce Comeaux, Amit Singh, B. Lindsey","doi":"10.2118/196150-ms","DOIUrl":"https://doi.org/10.2118/196150-ms","url":null,"abstract":"\u0000 Acid-tunneling is an acid jetting method for stimulating carbonate reservoirs. Several case histories from around the world were presented in the past showing optimistic post-stimulation production increases in open-hole wells, comparing to conventional coiled tubing (CT) acid jetting, matrix acidizing, and acid fracturing. However, many questions about the actual tunnel creation and tunneling efficiency are still not answered. In this paper, the results of an innovative full-scale research program involving water and acid jetting are reported for the first time.\u0000 The tunnels are constructed through chemical reaction and mechanical erosion by pumping hydrochloric (HCl) acid through conventional CT and a bottom-hole assembly (BHA) with jetting nozzles and two pressure-activated bending joints that control the tunnel initiation directions. If the jetting speed is too high and the acid is not consumed in front of the BHA during the main tunneling process, then unspent acid flows toward the back of the BHA and creates main wellbore and tunnel enlargement with potential wormholes as fluid leaks off, lowering the tunneling length efficiency.\u0000 Full-scale water and acid jetting tests were performed on Indiana limestone cores with 2-4 mD permeability and 12-14% porosity. Many field-realistic combinations of nozzle sizes, jetting speeds, and back pressures were included in the testing program. The cores were 3.75-in. in diameter by 6-in. in length for the water tests, and 12-in. in diameter by 18-in. in length for the tests with 15-wt% HCl acid. The jetting BHA was moved as the tunnels were constructed, at constant force on the nozzle mole, to minimize the nozzle stand-off distance. Six acid tests were performed at the ambient temperature of 46F and two at 97F. The results from the acid tests show that the acid tunneling efficiency can be optimized by reducing the nozzle size and pump rate. The results from the water and acid tests with exactly the same parameters to match the actual CT operations in the field show that the tunnels are constructed mostly by chemical reaction and not by mechanical erosion. The acid tunneling efficiencies obtained from the full-scale acid tests are superior to the average tunneling efficiency of more than 500 actual tunnels constructed during more than 100 acid tunneling operations performed to date worldwide.\u0000 The paper describes the full-scale water and acid jetting tests on Indiana limestone cores. The major novelty of this test program consists of performing all measurements with back pressure, unlike all previous water and acid jetting studies reported in literature, to more accurately mimic the downhole well conditions. The novel understanding of the combined effect of the nozzle size, pump rate, and back pressure significantly improves the actual acid-tunneling efficiency.","PeriodicalId":325107,"journal":{"name":"Day 1 Mon, September 30, 2019","volume":"264 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":"131475420","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":"Depletion-Induced Poroelastic Stress Changes in Naturally Fractured Unconventional Reservoirs and Implications for Hydraulic Fracture Propagation","authors":"Lei Jin, M. Zoback","doi":"10.2118/196215-ms","DOIUrl":"https://doi.org/10.2118/196215-ms","url":null,"abstract":"\u0000 Numerous questions surround stimulation and depletion in unconventional reservoirs with many important implications. Understanding depletion-induced stress changes is critical for designing in-fill drilling and avoiding phenomenon such as hydraulic fracture growth into depleted areas and hydraulic fractures from in fill wells affecting pre-existing wells (the frac-hit or parent well/child well phenomenon). In this paper, we utilize a fully coupled fracture-poro-mechanical computational model described by Jin & Zoback (https://doi.org/10.1002/2017JB014892) to evaluate the pressure and stress changes associated with pore-scale flow from the low permeability matrix into a much more permeable discrete fracture network. These fractures represent pre-existing natural fractures stimulated in shear during hydraulic fracturing as well as the hydraulic fractures themselves. Because of the marked permeability contrast, depletion is rather heterogeneous and can be visualized as halos adjacent to the more permeable shear fractures and hydraulic fractures. While this might be expected, the calculations are helpful in understanding the extent of depletion and limitations of utilizing the concept of a stimulated reservoir volume to predicting production. To examine the evolutions and characteristics of depletion-induced stress changes, we consider three cases representing different initial pore pressure, horizontal stress anisotropy and pressure drawdown. We show that while the total normal stress decreases overall due to depletion as expected, the changes are anisotropic due to the pressure gradient oriented predominantly perpendicular to the well; the changes are also highly heterogeneous due the presence of fractures and unexpected local increases among fractures can occur. Additionally, newly induced shear stress also develops with heterogeneous distributions. These changes jointly produce complex magnitude variations and rotational patterns of the horizontal principal stresses. For the base case we consider (high initial stress anisotropy, low initial overpressure and insignificant depletion), rotations occur mostly surrounding the fractures and the degree of rotation is mild. In marked contrast to this, in a case in which there is high initial overpressure, little horizontal stress anisotropy and significant depletion, rotations become less dependent on fractures and is prominent throughout the domain to a degree such that the directions of the two horizontal principal stresses are essentially flipped. Taken together, these calculations help illustrate how depletion-induced stress changes can affect problems like in-fill drilling and re-stimulation and therefore provide insights into better drilling and completion designs.","PeriodicalId":325107,"journal":{"name":"Day 1 Mon, September 30, 2019","volume":"66 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":"115142830","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":"Rapid Development and Deployment of a High Expansion Retrievable V0 Bridge Plug","authors":"Anthony Phan, S-R Yin, Richard Decena Ornelaz, Geir Jørgensen","doi":"10.2118/195842-ms","DOIUrl":"https://doi.org/10.2118/195842-ms","url":null,"abstract":"\u0000 This paper presents the rapid development of a high expansion retrievable V0-rated bridge plug that effectively leveraged engineering simulation and additive manufacturing to design, optimize, and qualify the new plug in accordance with the ISO14310 and API11D1 standards. This technology was mobilized for deployment into a customer well within less than 12 months.\u0000 For this project, a major Norwegian continental shelf (NCS) operator required a high expansion wireline retrievable bridge plug with a small outside diameter (OD) that was capable of gas-tight zonal isolation in 7 in. tubing while meeting the ISO14310 and API 11D1 V0 classifications. To address this challenge, several design concepts were developed using computer-aided design (CAD) and simulated using finite element analysis (FEA) to determine the optimal design and to establish the design factor of safety. Initial prototype testing showed unexpected failures of the mechanical backup system as a result of non-uniform loading from the rubber element, which had been assumed to be evenly distributed for the initial FEA. Leveraging FEA to verify the failure mode increased its fidelity and enabled successful generation of alternate solutions with an alternate material, in this case nickel alloy 718. A revised mechanical backup system was manufactured within three weeks using internal direct metal additive manufacturing capability; it was successfully validated within an additional two weeks. The final V0 trials were successfully completed a month later with additively manufactured components, and the technology was mobilized for deployment into the operator’s well within less than 12 months.\u0000 The successful design, development, and mobilization of the 7-in. high expansion V0-rated bridge plug within only 12 months demonstrates how FEA modeling and additive manufacturing can be successfully leveraged to reduce development timelines while identifying and producing innovative solutions. Speed to market and the delivery of robust solutions on time are becoming more critical in the cost-constrained oil market; consequently, tools such as FEA and additive manufacturing are increasingly becoming fundamental methods for meeting these new challenges, as demonstrated by the 7-in. high expansion V0 bridge plug project.\u0000 This paper shows how leveraging FEA in conjunction with fundamental testing failure analysis can be critical to overcoming technical challenges. Furthermore, combining these capabilities with additive manufacturing can accelerate timelines and increase the probability of project success and operator satisfaction.","PeriodicalId":325107,"journal":{"name":"Day 1 Mon, September 30, 2019","volume":"13 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":"125361933","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}