Day 2 Wed, February 02, 2022最新文献

{"title":"Parent-Child Well Relationships Across US Unconventional Basins: Learnings from a Data Analytics Study","authors":"J. Cozby, M. Sharma","doi":"10.2118/209171-ms","DOIUrl":"https://doi.org/10.2118/209171-ms","url":null,"abstract":"\u0000 Parent-child wells are horizontal wells drilled in close proximity to each other in unconventional basins. Simulation work in the technical literature demonstrates how depletion and fracture communication between parent and child wells can lead to child well underperformance. High-level, basin-wide data analysis of unconventional basins confirms this effect. However, as completion designs evolve and more state-of-the-art horizontal wells are completed in these basins, it is necessary to revisit this analysis and make adjustments and additions to the previous body of work. Specifically, initial production differences between parent and child wells need to be correlated to cumulative production differences, and more analysis regarding the effect of timing and spacing are needed. In this study, parent-child well pairs for wells completed within the last seven years in nine different unconventional basins are identified using a Python code applied to Enverus public data obtained in November 2020. These basins include the Bakken, Delaware, Eagle Ford, Haynesville, Marcellus/Utica, Midland, Niobrara, Powder River, and Scoop/Stack Basins. Our Python code also performs calculations to create the necessary comparative metrics for analysis. Four cumulative production proxies are created and First 12 Months BOE (barrel of oil equivalent) is chosen as the appropriate metric for analysis. Basin-to-basin comparisons are conducted, and the effects of well spacing and infill timing are investigated. The study finds that as stated in the technical literature, child well performance increases with spacing and decreases with infill timing. We show that parent cumulative production (BOE) at child well completion is a better indicator of child well performance. Overall, these assessments can help operators manage child well underperformance and can help them understand the effects of differing well spacing and infill timing on child well performance in different US unconventional basins.","PeriodicalId":224883,"journal":{"name":"Day 2 Wed, February 02, 2022","volume":"284 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-01-25","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121370943","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":"Linking Flowback Recovery to Completion Efficiency: Niobrara-DJ Basin Case Study","authors":"T. Moussa, Jessica Barhaug, D. Witt, R. Hawkes, H. Dehghanpour","doi":"10.2118/209136-ms","DOIUrl":"https://doi.org/10.2118/209136-ms","url":null,"abstract":"\u0000 Near wellbore complexity is a current topic of discussion among geoscience and engineering disciplines across North America. Asset teams are constantly investing money and resources into the variety of near- and far-field wellbore diagnostic techniques to ascertain completion efficiency. These range from high-cost microseismic for far-field fracture placement to higher risk technologies such as fiber optics, cameras, and production logging tools. These techniques are generally used for parameter constraints for rate-transient-analysis (RTA) that requires months (and sometimes years) of production after post-frac flowback. Therefore, in this study we utilize flowback water-oil-ratio (WOR) as a diagnostic tool to provide early-time feedback for completion-efficiency evaluation.\u0000 We analyze flowback, post-flowback and completion-design data of 19 multi-fractured horizontal wells (MFHWs) completed in Niobrara and Codell formations that are classified into parent and child groups. Child wells are then sub-clustered into Zipper-1 and -2 completed with more and less intense completion strategy, respectively. First, we analyze the flowback rate and pressure profiles of the 19 wells to estimate initial pressure in the stimulated area around wellbore and validate it against the outcomes of diagnostic fracture injection test (DFIT). Second, we apply rate-normalized-pressure (RNP) diagnostic analysis to a) investigate flow regimes during flowback and post-flowback periods; and b) assess interference between parent and child wells. Third, we use WOR diagnostic plots to estimate ultimate load recovery (ULR) and calculate initial effective fracture volume as two indicators for completion efficiency. We also cross-check the estimated effective fracture volume with microseismic dimensions. Finally, we apply rate-decline analysis on oil production data to predict ultimate oil recovery (UQo), assuming a critical oil rate of 1 stbd, and use it as a third performance indicator to evaluate the completion-design efficiency of each group.\u0000 Child wells show 32% more load recovery compared with the parent wells. However, the parent wells show 38% and 50% more 9-months cumulative oil production (Qo) and UQo, respectively. For both the parent and child wells, more than 50% of the predicted ULR is produced back within the first three months of production. Although the intense completion-design strategy for Zipper-1 wells led to 35% larger effective fracture volume compared to Zipper-2 wells, both groups show similar oil recovery performance. Generally, Niobrara wells show less load recovery and effective fracture volume compared to Codell wells in each completion group.","PeriodicalId":224883,"journal":{"name":"Day 2 Wed, February 02, 2022","volume":"30 7","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-01-25","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114126990","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":"Observation Lateral Project: Direct Measurement of Far-Field Drainage","authors":"C. Cipolla, Jennifer Wolters, Michael G. McKimmy, Carlos Miranda, Stephanie Hari-Roy, Aicha Kechemir, Nupur Gupta","doi":"10.2118/209164-ms","DOIUrl":"https://doi.org/10.2118/209164-ms","url":null,"abstract":"\u0000 In 2019 the operator embarked on a very ambitious data acquisition project in the Bakken, with the goal of mapping far-field drainage and characterizing completion performance. The project consisted of a six-well pad (10,000 ft laterals) with a dedicated observation lateral located in the Three Forks (TF) formation instrumented with cemented pressure gauges and fiber optics along the 10,000 ft lateral. The observation lateral was offset by Middle Bakken (MB) wells ∼450 ft on either side (∼900 ft MB-MB well spacing). One of the MB wells was instrumented with fiber optics for cluster-level completion measurements and \"frac hit\" detection, while the other offset MB well was used to deploy geophones for microseismic mapping. Three different fracture treatment designs were evaluated, with the goal of understanding how fluid volume & rheology, proppant volume and size, and proppant/fluid ratio affect fracture geometry and drainage. Quantitative application of oil and water tracers was used to evaluate the productivity of each treatment design.\u0000 During the completions of the first three wells, microseismic data provided important measurements to characterize fracture geometry and \"offset well\" fiber provided strain data to evaluate fracture morphology (i.e. – far-field fracture behavior). Stress shadowing was evaluated by combining the microseismic and strain data. These measurements were used to calibrate a hydraulic fracture model to enable more reliable predictions of fracture geometry and morphology. Cluster-level measurements of fluid distribution provided data to support increasing clusters/stage and decreasing stage count. Production has been continuously monitored for over 12 months, including interference testing to evaluate connectivity. The pressure gauges placed along the observation lateral provided one of the first-ever measurements of far-field drainage as a function of fracture treatment design (450 ft in between two producing wells, 900 ft well spacing).\u0000 The results show that MB wells can drain the TF at distances of 450 ft and fracture treatment design can significantly impact drainage and productivity. Although the evaluation, modeling, and trials are ongoing, these results may add significant value by enabling Bakken development with fewer, more productive, wells in some portions of the basin.","PeriodicalId":224883,"journal":{"name":"Day 2 Wed, February 02, 2022","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-01-25","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133459457","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":"Look Who’s Talking – Quantifying the Lasting Effects of Fracture-Driven Interactions","authors":"C. Senters, Rachel Harper, S. Jayakumar, D. Leonard, Mark N. Warren, R. Woodroof","doi":"10.2118/209124-ms","DOIUrl":"https://doi.org/10.2118/209124-ms","url":null,"abstract":"\u0000 Fracture-driven interactions (FDI’s) occur on most modern drilling and completion programs. These well-to-well interactions can be of benefit, but it is often difficult to quantify the lasting effects of these interactions and benchmark it for comparison.\u0000 The approach for quantifying the effects of fracture-driven interactions in this paper is to compare the magnitude and duration of communication events identified by chemical tracers for wells in a specific basin. Metrics are established to compare communication between projects to determine the effects of \"common contributors\" to significant fracture-driven interactions. The common contributors compared in this paper are well spacing, depletion effects from prior production, perforation cluster design, geologic features, and stimulation treatment design.\u0000 A \"Communication Intensity\" metric (CI) is established to quantify the amount of communication taking place on a particular pad or project. This is computed for hundreds of projects across a basin or multiple basins. The CI is used as a performance indicator to compare current project-level communication to area or basin-level benchmarks. Case histories are presented in this paper that utilize the CI metric to determine the effects of common contributors of well communication to established basin benchmarks. In addition to project-level communication, localized (well-level) communication events are investigated to determine the cause of the individual event and if any preventative or mitigative strategy could have been applied in the job design or execution phase.\u0000 Few if any industry benchmarks are available to compare the immediate, intermittent, and lasting effects of fracture-driven interactions (FDI’s) on a project or well level. The results of this paper outline a process for comparing projects to optimize well spacing and fracturing treatment design, as well as reflect on known and unknown features contributing to significant interactions.","PeriodicalId":224883,"journal":{"name":"Day 2 Wed, February 02, 2022","volume":"20 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-01-25","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134368799","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":"Feasibility of Using Drill Cuttings as Proppants in Unconventional Reservoirs","authors":"Fabián-Alfredo Carrascal-Delgado, S. Abedi, A. Hill, D. Zhu","doi":"10.2118/209173-ms","DOIUrl":"https://doi.org/10.2118/209173-ms","url":null,"abstract":"\u0000 Unconventional reservoirs are commonly drilled using oil-based mud, creating drill cuttings that are contaminated with hydrocarbons. Drill cuttings disposal is regulated by the state. The drill cuttings are usually disposed of by trucking them to a landfill. The economic and environmental impact is a challenge to the industry. In this study, we have investigated the feasibility of disposing of drill cuttings at the well site by mixing them into the proppant slurry as a part of the proppant during multi-stage hydraulic fracturing. Our study focused on whether the addition of drill cuttings, often composed of very fine particles, significantly impair the conductivity of the proppant pack created in the reservoir. The study provides an environmentally friendly solution to the drill cutting disposal problem with the procedures and limitations, and it helps to reduce the cost of fracturing operations.\u0000 Using actual drill cuttings samples from an Eagle Ford well, we have measured the fracture conductivity of mixtures of proppant and drill cuttings for a wide range of drill cuttings fractions. The cuttings-sand mixtures were evaluated following a modified API RP-61 procedure. A conductivity cell was used to perform short-term conductivity experiments applying dry nitrogen gas as fluid, with closure stress applied in incremental steps of 1000 psi from 1000 to 6000 psi. The cuttings were evaluated wet, as received from the rig site after mechanical separation on site, and dried, after being washed for removal of drilling fluid, to compare the effect of drilling fluid in conductivity responses. The effect of cuttings size and chemical composition on conductivity was also studied. 40/70 and 100 mesh sand were used as the proppant.\u0000 The results showed that adding up to 25% drill cuttings to the proppant pack had an insignificant effect on the fracture conductivity. The 100-mesh sand proppant retained conductivity with drill cuttings added somewhat better than the 40/70 mesh sand proppant. Because the volume of drill cuttings created in drilling even a quite long lateral is much less than the volume of proppant pumped in just a single stage, our results show that drill cuttings could be disposed of by adding them to the proppant slurry at a rate less than 25% of the proppant rate without causing any deleterious effect on the fracture conductivity created.","PeriodicalId":224883,"journal":{"name":"Day 2 Wed, February 02, 2022","volume":"30 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-01-25","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125226692","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":"Modelling of Parent Child Well Interactions","authors":"D. Ratcliff, M. McClure, G. Fowler, B. Elliot, Austin Qualls","doi":"10.2118/209152-ms","DOIUrl":"https://doi.org/10.2118/209152-ms","url":null,"abstract":"\u0000 We performed a modeling study calibrating a coupled \"true\" hydraulic fracturing and reservoir simulator to a complex set of observations from a parent-child well pad in the STACK play located in the Anadarko Basin area of Oklahoma. The model was constrained by sealed wellbore pressure monitoring, interference testing, pressure responses during frac hits, production data, and responses to chemical treatment. It was possible to match the full set of observations in a single, continuous simulation by calibrating the fracture toughness and leakoff, the permeability and relative permeability, a parameter related to proppant transport, and parameters related to a ‘fracture conductivity damage’ mechanism built into the simulator. The ‘fracture damage’ calculations mimic the reaction of frac fluid with the formation fluid as they mix in a hydraulic fracture during and after a frac hit. The interpretation of ‘fracture conductivity damage’ is corroborated by production impacts after frac hits, positive response to chemical mitigation treatments, and direct sampling of material from the wellbore. Because of the volume and quality of calibration data available, it is possible to constrain the key uncertainties of the model. It can now be used to design strategies to mitigate negative impacts from parent/child interactions.","PeriodicalId":224883,"journal":{"name":"Day 2 Wed, February 02, 2022","volume":"34 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-01-25","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124325452","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":"Spatial and Temporal Effects on Low Frequency DAS and Microseismic Implications on Hydraulic Fracture Geometry and Well Interactions","authors":"G. Ugueto, J. Haffener, S. Mondal, Alexei A. Satviski, P. Huckabee, K. Haustveit","doi":"10.2118/209180-ms","DOIUrl":"https://doi.org/10.2118/209180-ms","url":null,"abstract":"\u0000 Monitoring the geometry of hydraulically induced fractures using a variety of frac diagnostic tools is a relatively expensive but necessary step to achieve successful development of unconventional reservoirs. Valuable insights about the hydraulic fracturing process can be determined and cross-validated using an assortment of diagnostic tools. In recent years, the monitoring of pressure, temperature, and strain interactions between wells during stimulation has been providing new and detailed information about the geometry of hydraulic fractures not available before. Low Frequency Distributed Acoustic Sensing (LF-DAS) and Distributed Strain Sensing (DSS) can be used to determine the timing and location of approaching, intercepting and re-opening hydraulically induced fractures in nearby wells instrumented with Fiber Optics (FO). In the Hydraulic Fracture Test Site 2 (HFTS2) the integration of these technologies with traditional fracture geometry diagnostic tools such as Microseismic (MS) are revealing unique information about fracture geometry and the propagation tendencies of fractures generated while stimulating the Wolfcamp in the Permian Delaware Basin. In HFTS2, hydraulic fractures are sub-vertical, occurring in swarms and forming well-defined and separate Frac-Zone-Domains (FZDs). In HFTS2, both the number of microseismic events and strain interactions increase as stimulation progresses within the pad. The observed spatial and temporal dependencies in the MS and LF-DAS datasets strongly suggest there is a lot of re-opening and re-fracturing of pre-existing fractures, not only of the FZDs from the \"parent/primary\" wells but also from pre-existing fractures of the FZDs from offset \"child/infill\" wells that are part of the same stimulation vintage. These newly observed spatial and temporal effects must be considered when using MS, LF-DAS, and other fracture driven interaction (FDI) techniques to determine fracture growth velocities and when interpreting frac diagnostics results to calibrate fracture models. The data suggest that fracture growth is impacted by the location of pre-existing hydraulic fractures and their stress state. The findings in HFTS2 highlight the risk not only of misinterpreting microseismic derived Stimulated Rock Volume (SRV) but also, and more importantly the development of possible new completion practices and wells stimulation sequencing. The information from HFTS2 has helped to understand not only the fracture geometry on this Permian Wolfcamp site but also the uses and limitations of different fracture diagnostic tools.","PeriodicalId":224883,"journal":{"name":"Day 2 Wed, February 02, 2022","volume":"22 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-01-25","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121907367","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}