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Collaborating Authors
Noble Energy
Abstract In recent years, well performance from tight reservoirs in the Delaware Basin has been improving due to enhanced completion practices, better reservoir targeting and improved well designs in the region. One of the key components to the enhanced completion practices has been the implementation of progressively longer laterals. The rate of increase in lateral lengths have slightly slowed in recent years, as operators approach the point of no additional value creation as the well costs supersede the production gained from longer wells. This paper presents a tool created to evaluate the performance and economics of a given well given different reservoir, fluid, well design and completion parameters. The tool is also a probabilistic model that can quantify the impact of input parameters that the user feels uncertain about. As a result, it can provide management teams with an approach to make capital decisions under uncertainty. The proposed methodology presented in this paper is repeatable for different tight rock formations across different basins. An example of the tool's capability is demonstrated in this paper using an asset profile typical of the Delaware Basin's Wolfcamp A.
- North America > United States > Texas (1.00)
- North America > United States > New Mexico (1.00)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (23 more...)
The deep-water sub-salt carbonate reservoirs in Brazil are important plays that draw the attention of the E&P community. However, accurately characterizing the sub-salt reservoirs is still a challenging task due to the difficulties in the sub-salt imaging, velocity model building, and data quality and resolution. In this study, we explore a set of analytic predictive models to extend beyond the traditional reservoir characterization practice, which may be constrained by the data quality and the limitations of the 1D convolution model, thus allowing for an improved characterization of the ultra-deep sub-salt reservoirs, offshore Brazil. Our studied area is located in the Bรบzios field, Santos Basin, offshore Brazil. We start with the petrophysical analysis, followed by facies classification, and AVO inversion. Finally, we predict rock properties from the 3D seismic volume by applying an integrated interpretation procedure that utilizes data analytic techniques, which incorporate seismic inversion results, facies predictions, well logs and geological interpretation. The predicted 3D reservoir properties show a good match with well data. Presentation Date: Wednesday, October 14, 2020 Session Start Time: 1:50 PM Presentation Time: 4:20 PM Location: 360D Presentation Type: Oral
- Geology > Rock Type > Sedimentary Rock (0.52)
- Geology > Geological Subdiscipline > Geomechanics (0.37)
- Geophysics > Seismic Surveying > Seismic Processing (1.00)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling > Seismic Inversion (1.00)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Santos Basin > Block BM-S-11 > Buzios Field > Guaratiba Formation (0.99)
- South America > Brazil > Brazil > South Atlantic Ocean > Santos Basin (0.99)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic modeling (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
Application of Both Physics-Based and Data-Driven Techniques for Real-Time Screen-Out Prediction with High Frequency Data
Sun, Jianlei John (Noble Energy) | Battula, Arvind (Noble Energy) | Hruby, Brandon (Noble Energy) | Hossaini, Paymon (Noble Energy)
Abstract During hydraulic fracturing treatments, screen-out has caused delay in placement of subsequent stages, stand-by of on-site teams, loss production and safety concerns. Current prediction methods rely on either post-minifrac diagnostic or pure physics-based approaches, which were not always appropriate for real-time applications. This study uses data-driven methods like deep neural networks along with physics-based approach (i.e., Inverse Slope Method) to provide advanced warning of screen-outs in real-time. With domain knowledge, 65 screen-out stages in the Niobrara-DJ Basin were labeled into output binary indicators with or without screen-out. Input datasets include surface treatment pressure, slurry rate, surface proppant concentration and 11 engineering features in high frequency 1-second time interval. 65 stages were first split into 53, 8, and 5 stages for training, validation and test, respectively. Then, modified inverse slope method was utilized to predict screen-out, and three parameters were optimized such as slope duration, slope change, minimum slope value. Then, a baseline model and another advanced deep neural network-based model (CNN-LSTM) were trained, and CNN-LSTM model architecture was optimized by tuning hyperparameters. The final ensemble model was created as weighted average of the modified inverse slope and CNN-LSTM models. The ensemble model showed high precision, recall, f1-score and Area Under the Curve (AUC) of ROC curves for the validation and test datasets, and confusion matrices indicated better performance than either model alone. The implemented workflow is applicable to detect anomalies in real-time for high-frequency time series. In addition, it can handle automatic feature engineering, long-term time dependency, and leverage synergic effect of physics and machine-learning approaches. Introduction During hydraulic fracturing, large amount of fracturing fluids is pumped downhole to create fractures which are filled with proppant particles. However, when the proppants carried in the fluid create a bridge across the perforations or similar restricted flow area, it creates a sudden and significant restriction to fluid flow that causes a rapid rise in pump pressure, i.e., screen-out (Schlumberger 2020). Screen-out causes stand-by status, delay in the placement of subsequent stages, wellbore cleanout operations, and lost production days. Therefore, advanced warning of screen-out is critical to improve operation safety and efficiency.
- North America > United States > Wyoming > DJ (Denver-Julesburg) Basin > Niobrara Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- (5 more...)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Neural networks (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Artificial intelligence (1.00)
Abstract The purpose of this study was to develop a physical understanding of the bit damage that occurs in the Brushy Canyon and Avalon formations in the southern Delaware Basin and to develop practices to mitigate it. The operator had already implemented a programmatic initiative to move the organization toward physics-based, limiter-redesign workflows in order to achieve performance gains in a safe and efficient operation. A significant performance limiter was trips for damaged bits. Two dominant causes of bit damage were observed. One was tangential overload of the outside cutters, which tends to occur if hard streaks are exited with high WOB and depth of cut (DOC). The second is continuous wear of the outside cutters that occurs if lower WOB is used to avoid the tangential overload. There was no operating window in which any given WOB did not enable one or the other form of damage in 12-1/4โณ holes. An explanation of how the overload may occur is presented along with the results of changes in field practices that were consistent with the concept. The progress that was made was partly due to physics-based training of operations personnel which enabled them to interpret observed behaviors and manage dysfunction more intensely. Some elements of the physics-based workflow and training are also discussed at length because they are integral to the improvements achieved in performance (Dupriest 2005, 2006); particularly the use of a Geologic Roadmap and surveillance of the Baseline MSE. Bits from two wells drilled were pulled green after drilling from the surface casing through the Brushy Canyon. While this is encouraging the results from rig to rig was inconsistent. Bit design needs were identified that should enable higher success, and some of these features are now found in the current market. They were not available at the time of this initiative in 2018. The nature of the interfacial severity damage varies from the southern to northern end of the Delaware basin, with laminar calcite streaks dominating in the south (the operator's acreage) and nodular chert inclusions occurring in some areas of the north. Both create high loading of a small number of cutter studs and the real time and engineering design practices that limit the interfacial severity damage discussed in this paper may be useful across the basin.
- North America > United States > Texas (1.00)
- North America > United States > New Mexico (1.00)
- Geology > Rock Type > Sedimentary Rock (0.66)
- Geology > Geological Subdiscipline > Geomechanics (0.46)
- North America > United States > Texas > Permian Basin > Delaware Basin (0.99)
- Asia > Middle East > Qatar > Arabian Gulf > Rub' al Khali Basin > North Field (0.99)
- North America > United States > New Mexico > Permian Basin > Brushy Canyon Formation (0.94)
- (3 more...)
- Well Drilling > Drilling Operations (1.00)
- Well Drilling > Drill Bits > Bit design (0.89)
- Well Drilling > Drillstring Design > Torque and drag analysis (0.68)
Abstract Research and development drives success in shale plays throughout the world, enabling operators to deploy new drilling, completions, and production technologies to reach more reservoir area and extend the life of production wells. This work demonstrates the development, validation, and deployment of an extreme torque casing connection addressing technical challenges of tubulars in unconventionals. Throughout the well lifetime, Oil Country Tubular Goods (OCTG) experience various loads during the installation, stimulation, and production phases. Some of the challenges experienced during the stimulation and production phases relate to internal and external pressure resistance, sealability, corrosion and cracking, erosion, and wear. Furthermore, with the increase in lateral length and the more demanding well geometries, the OCTG capabilities related to high cycle fatigue, connection runability, and torque limits become more important to safely and efficiently reach the total depth of the well and ensure integrity throughout well life. Another scenario in which the torque limit of an OCTG connection is important is rotating while cementing, a practice undertaken to mitigate sustained casing pressure, improve well integrity, and completion efficiency. We present the key elements in the development of a casing connection that overcomes these challenges and the decision process leading to a prototype. To prove the design concept, a fit-for-purpose testing protocol was adopted to validate its performance, replicating the installation, stimulation, and production phases under the expected loads. Once validated, a pilot involving casing installation, rotation while cementing and stimulation was completed in two wells, and its outcomes will be discussed in this work. This novel casing extreme torque connection, designed to overcome the application challenges, enables the installation of casing in longer laterals, together with the improvement of well integrity through rotation while cementing. The performance of the product, tested through a special procedure while ensuring reliability, was confirmed by the case study from the Niobrara shale. A new connection considering the challenges of wells in unconventional plays must account for several aspects from design to installation. We show the process, from the design stage and validation, leading to successful field deployment.
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.55)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.37)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.48)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Nebraska > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Kansas > Laramie Basin > Niobrara Formation (0.99)
- (2 more...)
Pitfalls and implementation of data conditioning, attribute analysis, and self-organizing maps to 2D data: Application to the Exmouth Plateau, North Carnarvon Basin, Australia
Ha, Thang N. (The University of Oklahoma) | Marfurt, Kurt J. (The University of Oklahoma) | Wallet, Bradley C. (Aramco Services Company) | Hutchinson, Bryce (Noble Energy)
Abstract Recent developments in attribute analysis and machine learning have significantly enhanced interpretation workflows of 3D seismic surveys. Nevertheless, even in 2018, many sedimentary basins are only covered by grids of 2D seismic lines. These 2D surveys are suitable for regional feature mapping and often identify targets in areas not covered by 3D surveys. With continuing pressure to cut costs in the hydrocarbon industry, it is crucial to extract as much information as possible from these 2D surveys. Unfortunately, much if not most modern interpretation software packages are designed to work exclusively with 3D data. To determine if we can apply 3D volumetric interpretation workflows to grids of 2D seismic lines, we have applied data conditioning, attribute analysis, and a machine-learning technique called self-organizing maps to the 2D data acquired over the Exmouth Plateau, North Carnarvon Basin, Australia. We find that these workflows allow us to significantly improve image quality, interpret regional geologic features, identify local anomalies, and perform seismic facies analysis. However, these workflows are not without pitfalls. We need to be careful in choosing the order of filters in the data conditioning workflow and be aware of reflector misties at line intersections. Vector data, such as reflector convergence, need to be extracted and then mapped component-by-component before combining the results. We are also unable to perform attribute extraction along a surface or geobody extraction for 2D data in our commercial interpretation software package. To address this issue, we devise a point-by-point attribute extraction workaround to overcome the incompatibility between 3D interpretation workflow and 2D data.
- Phanerozoic > Mesozoic > Cretaceous (0.49)
- Phanerozoic > Mesozoic > Triassic (0.46)
- Geology > Geological Subdiscipline > Stratigraphy (1.00)
- Geology > Structural Geology (0.93)
- Geology > Sedimentary Basin (0.66)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.30)
- Geophysics > Seismic Surveying > Surface Seismic Acquisition (1.00)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling (0.68)
- Oceania > New Zealand > South Island > South Pacific Ocean > Canterbury Basin (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Muderong Shale Formation (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Barrow Basin (0.99)
- Oceania > Australia > Western Australia > Carnarvon Basin (0.99)
An Eagle Ford Case Study: Improving an Infill Well Completion Through Optimized Refracturing Treatment of the Offset Parent Wells
Garza, Mary (Noble Energy) | Baumbach, Joshua (Noble Energy) | Prosser, James (Noble Energy) | Pettigrew, Spencer (Noble Energy) | Elvig, Kirsten (Noble Energy)
Abstract This case study reviews Noble Energy's completion design, execution, and results of an Eagle Ford infill well B3 and the refracturing (refrac) treatments pumped on the direct offsets referred to in this paper as wells A1 and A2. The refrac stimulations were planned to serve the joint purpose of frac hit protection of the existing parent wells' reserves and re-pressurization of depleted zones to improve the performance of the infill child well. Both chemical diversion and mechanical diversion pods were utilized on the bullhead style refrac to optimize lateral placement of fracturing fluid and proppant. The A1 refrac was pumped first with a larger job size of proppant, water, and diversion material. The A2 refrac, pumped second, was half the size of the A1. Instantaneous shut-in pressure (ISIP) and diversion pressure response data was captured at each stage for both wells. Infill well B3 was completed last with normal plug-and-perf operations and the optimum job size of the time. The child well B3 production will be compared to offset wells with no depletion risk as well as to a 2014 vintage infill (Y3) well that was completed with no refrac on the direct offsets (X1 and X2). The A1 refrac data showed a gradual trend of increasing ISIP and treating pressure throughout the job indicating a more uniform stimulation of the lateral. There is a sustained production uplift resulting in a 36% improvement in estimated ultimate recovery (EUR). The A2 refrac data showed anomalous ISIP and pressure spikes mid-way through the job indicating the stimulation was not accessing the entire lateral. This blockage downhole was caused by being too aggressive with the concentration of pods pumped per stage. Since the A2 was not effectively re-pressurized, there was negligible change to EUR when the well was returned to production. In comparing the two refracs, we concluded that a larger job (increased proppant, fluid, and diversion) with less concentrated but more frequent diversion drops will increase lateral coverage and more effectively protect the parent well reserves. The surface treating pressures of the infill B3 indicate new rock was stimulated and initial production results trend with offset well production of the area showing no impact from depletion. Contrasting this with the prior infill Y3 completed with no refracs on parent wells, the Y3 has lower initial production (IP) rates and EUR when compared to its offset wells showing an obvious impact from depletion. Additionally, the refrac'd parent well A1 saw an improvement in EUR while the non-refrac'd parent X1 saw EUR degradation. In conclusion, pumping optimized refracs on the offset parent wells will both protect parent well reserves and improve the performance of the child well.
The Importance of Overburden and Pore Pressure on Horizontal Stress Magnitude Determination; an Example From the Delaware Basin
Kozlowski, Kristen (Noble Energy) | Da Silva, Melia (Noble Energy) | Brown, David (Noble Energy) | Taylor, Jack (Noble Energy) | Willems, Heather (Noble Energy) | Watson, Tim (Noble Energy) | Burch, Don (Noble Energy) | Hutton, Trevor (Noble Energy) | Christensen, Chris (Noble Energy) | Manohar, Mohan (Noble Energy)
Abstract Accurate minimum horizontal stress determination is critical for well design, drilling operations efficiency and completions optimization. Prediction of minimum horizontal stress is often challenged in unconventional plays due to uncertainties in pore pressure and overburden stress estimation. Lack of direct fluid pressure measurements, and sparse data collection, especially in the overburden, can result in stress models that are poorly constrained. Additionally, the influence of carbonate and total organic carbon (TOC) on log response can further complicate pore pressure interpretation. This study from the southern Delaware Basin investigates the sensitivity of horizontal stress magnitude to variations in overburden stress and pore pressure by integrating regional gravity data, bottom-hole temperatures and elastic rock properties in a 3-D mechanical earth model. The integrated model was utilized to better characterize mechanical facies, pore pressure and in-situ stresses. Multiple approaches were used to characterize the shallow, complex overburden in order to test model parameter sensitivity in areas where well data are sparse. Overburden stress estimates can vary up to 4๏นช when using different methods for shallow density characterization. Integrating gravity inversion into the shallow density model allowed for a robust regional overburden to be quickly modeled, especially in areas with sparse well control. The impact is a more accurate estimate of minimum horizontal stress resulting from improved consistency in field wide calibration to mini-frac and casing shoe test information. Introduction The Delaware Basin, part of the larger Permian Basin in west Texas (Figure 1), has a complex depositional and burial history resulting in challenging pore pressure and in-situ stress interpretations. Overburden stress estimation in the Delaware Basin is strongly influenced by mineralogy and thickness variations of shallow, mixed-layer Ochoan evaporites. The western extent of the basin has experienced significant halite dissolution resulting in a complex mixture of anhydrite and halite layers that vary in both thickness and in lateral extent across the area. As the mineral densities of halite and anhydrite are very different (2.16 g/cc and 2.98 g/cc respectively, Mavko et.al, 1988), models that capture variations in halite and anhydrite layer thickness should be considered best practice.
- North America > United States > Texas (1.00)
- North America > United States > New Mexico (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.95)
- Geology > Mineral > Halide > Halite (0.88)
- (2 more...)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling (0.94)
- Geophysics > Gravity Surveying > Gravity Modeling (0.67)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (27 more...)
Optimizing the Deepwater Completion Process: Case History of the Tamar 8 Completion Design, Execution and Initial Performance - Offshore Israel
Healy, John (Noble Energy) | Waggoner, Steven M. (Noble Energy) | Magin, Ian (Noble Energy) | Beavers, Matt (Noble Energy) | Williams, Kevin (Noble Energy) | Hebert, Russell (Noble Energy)
Abstract A case history from Offshore Israel is presented that describes the successful delivery of one (1) ultra-high rate gas well (+250 MMscf/D) completed in a significant (11.5 TCF) gas field with 7 in. production tubing and an Open Hole Gravel Pack (OHGP). The well described, Tamar 8, was completed approximately 4 years after the start of initial production from the Tamar development. Several operational innovations and process improvements were implemented that resulted in a significant reduction in rig time. A novel multi-purpose integrated tool string design enabled the sequential drilling of the pilot hole, underreaming of the reservoir section, several fluid displacements and casing cleaning in a single trip. The completions were installed with minimal operational issues (completion Non-Productive Time, NPT = 2.6%). Production commenced in April 2017. The initial completion productivity of this new well exceeded the five wells completed in 2012. Peak production rate to date is 281 MMscf/D.
- Europe (1.00)
- North America > United States > Texas (0.69)
- Asia > Middle East > Israel > Mediterranean Sea (0.29)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.94)
- Geology > Mineral (0.68)
- North America > Trinidad and Tobago > Trinidad > North Atlantic Ocean > Columbus Basin > South East Galeota Block > Cannonball Field (0.99)
- Asia > Middle East > Israel > Mediterranean Sea > Southern Levant Basin > Mari-B Field > Yafo Formation (0.99)
- Asia > Middle East > Israel > Mediterranean Sea > Southern Levant Basin > Mari-B Field > Noa Formation (0.99)
- (5 more...)
Case History - Continued Diagnostic Technology Integration with Completions in Horizontal Wolfcamp Shale Wells in the Delaware Basin
Parker, Justin E. (Noble Energy) | Tran, Van P. (Bazan Consulting, Inc.) | Bazan, Lucas W. (Bazan Consulting, Inc.) | Thomas, Jonathan (Noble Energy) | Renze, Arden (Noble Energy)
Abstract Parker et. al., (2015), SPE 175535, presented an engineered completion methodology utilizing diagnostic technology integration relating to horizontal shale wells in the Delaware basin. That paper focused on technologies pertaining to hydraulic fracture design for the Wolfcamp A reservoir using a discrete fracture network (DFN) model for predicting fracture geometry, formation evaluation, oil tracers, microseismic monitoring and production history matching. The final results of the paper showed that the application of an integrated technology approach provided the operator with a systematic method for designing, analyzing, and optimizing multi-stage/multi-cluster transverse hydraulic fractures in horizontal wellbores. Since publishing the paper, the completion and fracture stimulation design methodology has been further extended with improved well performance. This new work presents longer term well results from the original paper and additional wells that have since been completed with design improvements based on this process. Further technologies have since been added to the completion processes which have enhanced well performance, including the application of rate transient analysis (RTA) analysis, applied post job engineering analytics (APJA), additional pressure history matching (PHM) and post-fracture pressure matches to help refine the DFN model. The purpose of this work will be to further outline the benefits of utilizing multiple diagnostic technology integration to design, analyze and optimize completion and fracture stimulation design in the Wolfcamp shale. Detailed discussion related to created and propped fracture half-lengths, estimates of minimum conductivity, perforation design and cluster efficiency are presented. The value of diagnostic technology, EUR considerations and well economics will also be addressed. Readers of this paper will gain insight on how sound engineering, fracture modeling and data integration can increase recovery and optimize completions in the Wolfcamp and Bone Spring formations. Those working in the Delaware and Midland basins can readily apply specific learnings from this work to new completions. Additionally, the methods and engineering principles presented in this paper will provide a basis-of-design to enhance productivity and well economics for horizontal wells in unconventional resources.
- North America > United States > Texas (1.00)
- North America > United States > New Mexico (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.81)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play > Shale Gas Play (0.61)