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Results
Enhancing Drill Bit Connections for Reliability and Longevity
Allison, Cliff (Baker Hughes Company) | Borders, Zachary (Baker Hughes Company) | Donaldson, Justin (Baker Hughes Company) | Grimes, Robert E. (Baker Hughes Company) | Lee, Roger K. (Baker Hughes Company) | Slavens, Stephen (Baker Hughes Company) | Daechsel, Dustin (Shell Oil Company)
Abstract Pursuit of drilling the technical limit has been a primary driver of cost and cycle time reduction from the onset in North America shale. This is increasingly evident in today's downhole mud motors, where motors designed to drill in 6.75 in. hole are now rated for 500+hp and over 10,000 ft-lbs of torque. Every unit of power added stresses current materials to the limit and increases the risk of mechanical failure. As will be demonstrated in the following sections, the increased power delivered to the bit now exceeds the strength and reliability of the standard 3 ยฝ REG connection for drill bits. The integrity and longevity of the drill bit pin connections is the primary focus of this paper. Details are provided of the technical aspects of drill bit solutions that meet current drilling requirements and recognizes industry trends that will continue to present future challenges for bit connections. This paper also describes the collaborative partnership between an operator and bit service provider that led to success and the development of a long term plan for continuing success.
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- (34 more...)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Well Drilling > Drill Bits > Bit design (0.96)
- Well Drilling > Drilling Operations > Directional drilling (0.94)
- Well Drilling > Drillstring Design > Drill pipe selection (0.68)
Adaptation of Crushed Rock Analysis to Intact Rock Analysis To Improve Assessment of Water Saturation and Fast Pressure Decay Permeability
Cheng, Kai (GeoMark Research, Ltd) | Zumberge, J. Alex (GeoMark Research, Ltd) | Perry, Stephanie E. (GeoMark Research, Ltd) | Lasswell, Patrick M. (GeoMark Research, Ltd) | Vodo, Themi (GeoMark Research, Ltd)
Summary Legacy crushed rock analysis, as applied to unconventional formations, has shown great success in evaluating total porosity and water saturation over the previous three decades. The procedure of crushing rock into small particles improves the efficiency of fluid recovery and grain volume measurements in a laboratory environment. However, a caveat to crushed rock analysis is that water and volatile hydrocarbons evaporate from the rock during the preparatory crushing process, causing significant uncertainty in water saturation assessment. A modified crushed rock analysis incorporates nuclear magnetic resonance (NMR) measurements before and after the crushing process to quantify the volume of fluid loss. The advancements improve the overall total saturation quantification. However, challenges remain in the quantification of partitioned water and hydrocarbon loss currently derived from the NMR spectrum along with its uncertainty. Furthermore, pressure decay permeability from crushed rock analysis has been reported to have two to three orders of magnitude difference between different laboratories. The calculated pressure decay permeability of the same rock could even vary by several orders of magnitude with different crushed sizes, which questions the quality of the crushed pressure decay permeability. In this paper, we introduce an intact rock analysis workflow on unconventional cores for improved assessment of water saturation and enhanced quantification of fast pressure decay matrix permeability from intact rock. The workflow starts with acquisition of NMR T2 and bulk density measurements on the as-received state intact rock. Instead of crushing the rock, the intact rock is directly transferred to a retort chamber and heated to 300ยฐC for thermal extraction. The volumes of thermally recovered fluids are quantified through an image-based process. The grain volume measurement and a second NMR T2 measurement are performed on post-retort intact rock. The pressure decay curve during the grain volume measurement is then used for calculating the pressure decay matrix permeability. Total porosity is calculated using the bulk volume and grain volume of the rock. Water saturation is quantified using the total volume of recovered water. In addition, the twin as-received-state rocks are processed through the crushed rock analysis workflow for an apple-to-apple comparison. Meanwhile, the pressure decay permeability of the post-retort intact sample is cross-validated against the steady-state gas permeability of the same post-retort sample. The introduced workflow has been tested successfully on different formations, including Bakken, Bone Spring, Eagle Ford, Cotton Valley, and Niobrara. The results show that total porosities calculated from intact rock analysis are consistent with total porosities from crushed rock analysis, while water saturations from the new workflow are an average 8% saturation unit (SU) [0.2 to 0.7% porosity unit (PU) of bulk volume water (BVW)] higher than those from the prior crushed rock workflows. The study also indicates that for some formations (e.g., Bone Spring), the fluid loss during the crushing process is dominated by water; however, for some other formations (e.g., Bakken), the hydrocarbon loss is significant. Pressure decay permeability quantified using intact rock analysis is also confirmed within an order of magnitude of steady-state matrix permeability.
- Europe > United Kingdom > England (0.28)
- North America > United States > Texas (0.28)
- Research Report > New Finding (0.67)
- Research Report > Experimental Study (0.48)
- North America > United States > Wyoming > Wind River Basin > NPR-3 > Muddy Formation (0.99)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.93)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.93)
- (15 more...)
Linking Flowback Recovery to Completion Efficiency: Niobrara-DJ Basin Case Study
Moussa, Tamer (University of Alberta) | Barhaug, Jessica (Great Western Operating Company LLC.) | Witt, Darby (Cordax Evaluation Technologies INC.) | Hawkes, Robert (Cordax Evaluation Technologies INC.) | Dehghanpour, Hassan (University of Alberta)
Abstract 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. 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. 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.
- North America > United States > Colorado (1.00)
- North America > United States > Texas (0.93)
Abstract 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.
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.94)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.94)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.94)
- (19 more...)
- Information Technology > Software > Programming Languages (0.54)
- Information Technology > Data Science > Data Quality (0.46)
Evaluate Wettability and Production Potential of Tight Reservoirs Through Spontaneous Imbibition Using Time-Lapse NMR and Other Measurements
Ali, Mansoor (WD Von Gonten Laboratories) | Ali, Safdar (WD Von Gonten & Co.) | Mathur, Ashish (WD Von Gonten Laboratories) | Von Gonten, William (WD Von Gonten & Co.)
Abstract Several studies have shown that rock-fluid interactions in tight rocks are influenced by the natural wettability behavior of the various pore systems. Studying the water/oil displacement on a smaller scale using core plug imbibition and monitoring with NMR is very insightful in evaluating wettability and distinguishing pore modes and rock types based on their fluid affinity. Extending learnings from plug-scale imbibition process to reservoir production behavior requires understanding of the underlying compositional and/or textural parameters controlling the wettability. This paper presents a systematic study of spontaneous imbibition of oil and water in core plugs procured from several tight and organic-rich reservoirs with varying mineral composition and organic content. The experiment comprised three identical core plugs from the same depth undergoing multiple fluid imbibition cycles with one plug starting in produced brine, the second one in produced crude and the last one in decane. Sample weights were continuously monitored and when stable, a sample which was in brine was moved to crude and the one in crude was moved to brine. This process was repeated for four cycles so that samples that started in brine finally ended up in crude and those that started in crude ended up in brine. The saturation changes and rock-fluid interaction in different fluid types were monitored using a 12 MHz NMR spectrometer. The 12 MHz NMR allowed very accurate partitioning of the oil-filled and water-filled porosity in these tight rocks, which was essential for the wettability analysis. The rate and extent of saturation changes varied significantly from sample to sample. The comparison between the companion plugs imbibing either higher amounts of oil or water revealed the fluid affinity of each sample. We computed the ratio of the net incremental fluid fraction to the total porosity to represent the dominant pore wetting system for rock samples at a given depth. We measured organic content and mineralogy of the samples and analyzed the matrix effect on wettability. We analyzed the post-imbibition NMR relaxation times (T1,T2) of individual fluid types and integrated with matrix properties to evaluate oil and water mobilities. We found predicted fluid mobilities to be consistent with the observed production from wells drilled in the different reservoirs and rock types. We observed most samples attain 100% fluid saturation within two to four cycles and almost all the samples at a given depth took up very similar water volumes irrespective of whether the companion plugs started in brine or crude. The process highlighted that water-wet pores governed the final water saturation, which was strongly correlated with total clay. The amount of organic content and carbonate minerals influenced the oil uptake and its relative mobility. For samples that started in decane, decane was imbibed faster and caused samples to attain higher oil saturation than samples that started in crude.
- Geology > Mineral (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.56)
- 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)
- (45 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Core analysis (0.89)
Adaptation of Crushed Rock Analysis to Intact Rock Analysis To Improve Assessment of Water Saturation and Fast Pressure Decay Permeability
Cheng, Kai (GeoMark Research, Ltd) | Zumberge, J. Alex (GeoMark Research, Ltd) | Perry, Stephanie E. (GeoMark Research, Ltd) | Lasswell, Patrick M. (GeoMark Research, Ltd) | Vodo, Themi (GeoMark Research, Ltd)
Summary Legacy crushed rock analysis, as applied to unconventional formations, has shown great success in evaluating total porosity and water saturation over the previous three decades. The procedure of crushing rock into small particles improves the efficiency of fluid recovery and grain volume measurements in a laboratory environment. However, a caveat to crushed rock analysis is that water and volatile hydrocarbons evaporate from the rock during the preparatory crushing process, causing significant uncertainty in water saturation assessment. A modified crushed rock analysis incorporates nuclear magnetic resonance (NMR) measurements before and after the crushing process to quantify the volume of fluid loss. The advancements improve the overall total saturation quantification. However, challenges remain in the quantification of partitioned water and hydrocarbon loss currently derived from the NMR spectrum along with its uncertainty. Furthermore, pressure decay permeability from crushed rock analysis has been reported to have two to three orders of magnitude difference between different laboratories. The calculated pressure decay permeability of the same rock could even vary by several orders of magnitude with different crushed sizes, which questions the quality of the crushed pressure decay permeability. In this paper, we introduce an intact rock analysis workflow on unconventional cores for improved assessment of water saturation and enhanced quantification of fast pressure decay matrix permeability from intact rock. The workflow starts with acquisition of NMR T2 and bulk density measurements on the as-received state intact rock. Instead of crushing the rock, the intact rock is directly transferred to a retort chamber and heated to 300ยฐC for thermal extraction. The volumes of thermally recovered fluids are quantified through an image-based process. The grain volume measurement and a second NMR T2 measurement are performed on post-retort intact rock. The pressure decay curve during the grain volume measurement is then used for calculating the pressure decay matrix permeability. Total porosity is calculated using the bulk volume and grain volume of the rock. Water saturation is quantified using the total volume of recovered water. In addition, the twin as-received-state rocks are processed through the crushed rock analysis workflow for an apple-to-apple comparison. Meanwhile, the pressure decay permeability of the post-retort intact sample is cross-validated against the steady-state gas permeability of the same post-retortsample. The introduced workflow has been tested successfully on different formations, including Bakken, Bone Spring, Eagle Ford, Cotton Valley, and Niobrara. The results show that total porosities calculated from intact rock analysis are consistent with total porosities from crushed rock analysis, while water saturations from the new workflow are an average 8% saturation unit (SU) [0.2 to 0.7% porosity unit (PU) of bulk volume water (BVW)] higher than those from the prior crushed rock workflows. The study also indicates that for some formations (e.g., Bone Spring), the fluid loss during the crushing process is dominated by water; however, for some other formations (e.g., Bakken), the hydrocarbon loss is significant. Pressure decay permeability quantified using intact rock analysis is also confirmed within an order of magnitude of steady-state matrix permeability.
- Europe > United Kingdom > England (0.28)
- North America > United States > Texas (0.28)
- Research Report > New Finding (0.67)
- Research Report > Experimental Study (0.48)
- North America > United States > Wyoming > Wind River Basin > NPR-3 > Muddy Formation (0.99)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.93)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.93)
- (15 more...)
Pressure Decline Analysis in Fractured Horizontal Wells: Comparison between Diagnostic Fracture Injection Test, Flowback, and Main Stage Falloff
Wang, HanYi (University of Texas at Austin (Corresponding author) | Elliott, Brendan (email: wanghanyi@areafrac.com) | Sharma, Mukul (now with AreaFrac Technology LLC))
Summary The pressure decline data after the end of a hydraulic fracture stage are sometimes monitored for an extended period of time. However, to the best of our knowledge, these data are not analyzed and are often ignored or underappreciated because of a lack of suitable models for the closure of propped fractures. In this study, we present a new approach to model and analyze pressure decline data that are available in unconventional horizontal wells with multistage, transverse hydraulic fracturing. The methods presented in this study allow us to quantify closure stress and average pore pressure inside the stimulated reservoir volume (SRV) and to infer the uniformity of proppant distribution without additional data acquisition costs. For the first time, field data of diagnostic fracture injection test (DFIT), flowback, and pressure decline of main fracturing stages from the same well are compared and analyzed. We found that the early-time main fracturing stage pressure decline trend is controlled by fracture tip extension, followed by progressive hydraulic fracture closure on the proppant pack, whereas late-time pressure decline reflects linear flow. When DFIT data are not available, pressure decline analysis of a main hydraulic fracturing stage can be a substitution if it can be monitored for an extended period to allow fracture closure on proppants and asperities.
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Texas > Permian Basin > Delaware Basin (0.99)
- North America > United States > Oklahoma > Anadarko Basin > Cana Woodford Shale Formation (0.99)
- (4 more...)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
Evaluating The Liquids Potential And Distribution Of West Virginia's Marcellus Liquids Fairway
Smith, Christopher (Advanced Hydrocarbon Stratigraphy) | Pool, Susan (West Virginia Geological and Economic Survey) | Dinterman, Philip (West Virginia Geological and Economic Survey) | Moore, Jessica (West Virginia Geological and Economic Survey) | Vance, Timothy (West Virginia Geological and Economic Survey) | Smith, Timothy (Advanced Hydrocarbon Stratigraphy) | Gordon, Patrick (Advanced Hydrocarbon Stratigraphy) | Smith, Michael (Advanced Hydrocarbon Stratigraphy)
Abstract The distribution of liquid hydrocarbon (HC) resources in the Marcellus Formation throughout West Virginia (WV) is a matter of economic importance for the State of West Virginia and Marcellus operators. Herein, the West Virginia Geological and Economic Survey (WVGES) and Advanced Hydrocarbon Stratigraphy (AHS) have undertaken a project to map the composition and quantities of liquid gasoline range HCs present in drilling cuttings from counties in and neighboring the WV liquids fairway using Rock Volatiles Stratigraphy (RVStrat). Cuttings were analyzed from 12 wells, including air drilled wells, from Doddridge, Marshall, Ritchie, Tyler, Harrison, and Wetzel counties; spud dates range from 1953-2013. Insights into the geographical distribution of liquids quantities and compositions and the regional petroleum system were gained with a focus on the Devonian-aged shales, i.e. the upper and lower Marcellus Formation and the West River and Geneseo shale members of the Genesee Formation. Major results were identification of apparent thermal maturity trends embedded in the liquids composition across the basin where there is a trend of increasing paraffin (alkane) and decreasing naphthene (cycloalkane) content as a function of depth. A trend of decreasing size (number of carbon atoms) of the liquid molecules vs depth was observed in the West River, Geneseo, and upper Marcellus indicative of thermal maturity. The liquids distribution across the Marcellus fits within expectations from production data showing a trend of increasing content moving westward from northcentral WV towards the Ohio River; liquid saturations measured were likely โค1% of the original subsurface saturation. The liquids content in the Marcellus shows an apparent declining exponential vs depth trend likely linked to the progression of catagenesis. An anomalous well that may have undergone a significant gas migration/expulsion event, resulting in less liquid content and a preferential depletion of the more volatile liquid HC species was identified. There is also a trend of increasing mechanical strength of the cuttings vs depth likely due to compaction; there are differences in mechanical strength as function of when the well was drilled, before or after 2009 (likely due to PDC [polycrystalline diamond compact drill bits); this was the only bias identified due to the age of the sample or mud system used. The value of being able to collect usable and meaningful geochemical data from air drilled wells where the cuttings are several decades old with minimal cuttings material by RVStrat should not be understated; it allows using samples that are typically considered unsuitable and offers unique opportunities for petroleum system assessments.
- North America > United States > Virginia (1.00)
- North America > United States > West Virginia > Wetzel County (0.24)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.87)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.76)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Texas > Permian Basin > Delaware Basin (0.99)
- North America > United States > Tennessee > Appalachian Basin (0.99)
- (50 more...)
A Novel Approach to Understanding Multi-Horizon Fluid Flow in Unconventional Wells Using Produced Water Time-Lapse Geochemistry: Powder River Basin, Wyoming
Jones, Peter (Devon Energy) | Dressler, Drew (Devon Energy) | Conner, Tyler (Devon Energy) | O'Brien, Josh (Devon Energy) | Klaassen, Trevor (Devon Energy (former)) | Bingham, Sean (Auburn University)
Abstract Objectives/Scope: Increasing focus has been directed towards value that can be derived from the analysis of produced water from unconventional wells. Work by Laughland et al. (2014), Wright et al. (2019) and Jweda et al. (2020) have shown that formation water from different zones can be recognized and distinguished from stimulation water. Although time-lapse geochemistry (TLG) studies may be designed for individual wells or lease development projects, companies typically have an abundance of water chemistry data that was obtained for various production-related issues. Devon is leveraging this data to provide value to geoscientists in active exploration and development areas. The historical data serve as a framework for supporting detailed TLG studies, as well as a resource that can be quickly drawn upon to assess a variety of operational issues. Through development of a Genetic Origin and Alteration Tool (GOAT), the identification of formation water from different horizons is enhanced. Additionally, GOAT provides an innovative application for unmixing produced waters from multiple contributing zones. The workflow assists in assessment of the stimulated rock volume (SRV) and changes in the communicating rock volume (CRV) over time. This is critical to understanding drainage behavior and vertical connectivity between multiple zones with stacked-well development patterns. Methods/Procedures/Processes: Produced water chemistry is influenced by factors including: the composition of the original water at time of deposition, proximity to salt and anhydrite, rock-water reactions relating to mineral diagenesis, depth/temperature, and fluid migration. Thus, the characteristics of formation water in adjacent horizons can vary greatly due to differences in the diagenetic pathway for each zone. The GOAT interpretive scheme uses a radar-plot with axes composed of ratios that highlight the common changes accompanying water diagenesis. Differences in shapes are used to quickly group water types and origin. The GOAT facilitates the processing of many samples, so that end-member components may be recognized for use in solving unmixing problems. Analytical methods used included standard water chemistry analysis with extended metal ions and isotopic geochemistry (ฮด18O and ฮดD).
- Geology > Sedimentary Geology (1.00)
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- (2 more...)
Abstract The US shale revolution in the past decade has doubled the country's crude production, and tight clay-rich formations account for 60% of the US crude production. Nevertheless, our knowledge of petroleum system controls on the reservoir performance of these tight shale systems remains poor. We report on a methodology to utilize production data to compare and rank the US shale oil plays in conjunction with geologic descriptions of the plays. For this study, we have used 36,642 horizontal oil wells from 12 tight shale formations in the Rockies and Midwest basins with vertical depths ranging from 5,000-15,000 feet and with at least 24 months of production to rank these plays based on their performance. These formations include: Wolfcamp (Delaware and Midland/Permian), Bone Spring (Delaware/Permian), Eagle Ford (Gulf Coast West and Central/ Cretaceous), Niobrara (Denver and Powder River/Cretaceous), Bakken (Williston/Devonian), Austin Chalk (Gulf Coast West/Cretaceous), Woodford (Anadarko/Devonian), Spraberry (Midland/Permian), and Barnett (Fort Worth/Mississippian). Their production data were normalized for cumulative oil (STB/ft/month), and the results were then analyzed in light of geologic and geochemical data from the formations. Integrated production and geologic-geochemical data on the tight formations offer valuable insights into the control of petroleum system elements on production patterns. These comparative patterns were used for ranking the shale plays for various parameters. In terms of cumulative oil production (STB/ft/month), Wolfcamp (Delaware) ranks top (0.93 STB/ft/month) while Barnett (Fort Worth) has the lowest crude production (0.07 STB/ft/month). In terms of GOR changes during production, Wolfcamp (Delaware) shows the lowest change (1.38 times), while Barnet (Fort Worth) has the highest change (13.37 times). These may be related to the oil-prone nature of Wolfcamp and the gas-prone characteristics of Barnet. Overall, deeper shale plays yield more oil (per foot per month) than the shallower plays. Some plays exhibit intra-formational migration of hydrocarbons. The results and the methodology of this study provide a multi-disciplinary geo-engineering to characterize shale oil plays in various basins. Variability in the performance of shale oil plays given by production data can be reverse engineered to petroleum systems.
- Phanerozoic > Paleozoic > Permian > Cisuralian (0.70)
- Phanerozoic > Mesozoic > Cretaceous > Upper Cretaceous (0.48)
- Phanerozoic > Paleozoic > Carboniferous > Mississippian (0.46)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (1.00)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Geological Subdiscipline > Economic Geology (1.00)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- (62 more...)