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Collaborating Authors
Zumberge, J. Alex
Abstract Traditional assessment of "free" oil-in-place via programmed pyrolysis can be challenged due to false positives (OBM invasion/interference), non-unique signatures (i.e. low temperature shoulders) or biased from sample handling procedures (unpreserved or ‘vintage’ core/cuttings). Additionally, estimated oil saturations and volumetrics of producible hydrocarbons from core material may be underrepresented if certain extraction practices are used. Here, we utilize an advanced thermal extraction technique that is tailored to optimize mobile bulk volumes of oil within a target horizon. Further geochemical assessment of the collected thermal extract aids in additional understanding of the hydrocarbons in place (source/maturity/migration). Retort oil evaluation via fine-tuned thermal extraction techniques can significantly increase estimated oil saturations and oil in place calculations. It’s important to note that the selected retort temperature regime for Formation X in Basin A may very well be different than Formation Y in Basin B due to variations in source rock (kerogen) type, thermal maturity and/or a number of other factors. Therefore, a tailored experimental set up for a specific formation of interest would provide the dataset with the highest confidence for saturation and producibility evaluations. Introduction When evaluating the geochemical makeup of hydrocarbons within a rock (core/SWC/cuttings/etc.), it is important to understand the effects that the chosen extraction technique has on the fluid that is being extracted. For instance, when using excess solvent in a Soxhlet or Dean Stark apparatus, the solvent must be evaporated off to concentrate the extract before analysis. During that evaporation phase, light- to mid-chain hydrocarbons (typically up to ∼nC15), which were potentially present in the parent rock sample, would also be lost before analysis even begins. If extraction of the heavier hydrocarbons was the goal, a solvent-based approach is appropriate but if light- to mid-chain hydrocarbons are dominant or if accurate original oil in place (OOIP) estimations are needed, then the loss of such hydrocarbons should be avoided.
- North America > United States > Texas (1.00)
- North America > United States > Colorado (0.94)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.34)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.75)
- North America > United States > Wyoming > Uinta Basin (0.99)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Utah > Uinta Basin (0.99)
- (10 more...)
Fluid Definitions and Pore Space Partitioning: Integrating NMR and Closed Retort Data
Zumberge, J. Alex (GeoMark Research) | Dick, Michael J. (Green Imaging Technologies) | Veselinovic, Dragan (Green Imaging Technologies) | Piper, Nathaniel C. (GeoMark Research) | Turner, Adam (GeoMark Research) | Milovac, Jadranka (GeoMark Research)
Abstract In this study, we investigated the use and effectiveness of two independent methodologies that quantify extracted fluid from a Niobrara core sample. The two approaches included a thermal extraction via closed retort and NMR analysis (T2 and T1-T2). Specifically, we aimed to compare the changes in NMR fluid signal against the fluid that was obtained through the closed retort thermal extraction to ultimately quantify the recovered water/oil volumes across a range of extraction temperatures (85°C to 300°C). Through these analyses, we expected to gain a better understanding of the relative advantages and limitations of these two approaches for quantifying fluids in unconventional resource reservoirs, which can help improve resource recovery and minimize economic impact. Introduction Understanding the pore space and fluid movements in unconventional rocks, such as organic-rich mudstones, is crucial for optimizing resource recovery in these complicated systems. Previous studies have employed standalone NMR to investigate these characteristics with some success, but interpretation of the data can be challenging due to the presence of heavy organic matter, fine to very fine grains, relatively small porosity and a complex pore system. To overcome these difficulties, this study proposes a novel approach that compares closed retort measurements against NMR observations. By doing so, the study aims to provide a more comprehensive understanding of fluid movements and pore space in unconventional resource reservoirs. Theory and/or Methods This experiment was performed on wax-sealed preserved core material, where one sample depth was selected, and a total of 6 crushed/homogenized cuts were created from this depth (Fig. 1). The core comes from the Powder River Basin within the Niobrara formation. It had a TOC of 2.0 wt. % with a thermal maturity of 0.81% Ro equivalent (as determined from Tmax from programmed pyrolysis; see Jarvie et al., 2001). The closed retort was supplemented with as received bulk density, as received grain density and post retort grain density measurements. Additional geochemistry measurements were included to better characterize rock/fluid interactions, including HAWK programmed pyrolysis after each retort temperature.
- North America > United States > Texas (1.00)
- North America > United States > Colorado (0.66)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.35)
- North America > United States > Wyoming > Powder River Basin (0.99)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Texas > Permian Basin > Delaware Basin (0.99)
- (6 more...)
Abstract Variability in geochemical mobility trends between formations and through production(?) time is critical data to be integrated for commercial optimization. Mobility changes are attributed to fluid and rock interactions in low permeability systems, but most learnings are based on proxy data. An important measured trait of these systems is the preferential flow of straight chained saturated molecules over aromatics (Sat versus Aro). Therefore, produced fluids with higher mobility indicators (higher saturate to aromatic ratios) are indicative of either secondary migration or lower permeability rock while lower mobility indicators are indicative of either nearer proximity to source or higher permeability rock. Here, rock samples from wells in the Powder River Basin are used to refine mobility understandings. Core samples from two wells at the Powder River Basin were thermally extracted via closed retort. Subsequently, geochemical characterization of the resulting retort oils (thermal extracts) was performed to quantify the ratio of saturates to aromatics, a measurement of fluid mobility. The results of the characterizations were compared to rock properties (measured through x-ray diffraction and log properties). Results illustrate relationships between the mobility of hydrocarbons and rock properties of the reservoir. The present study highlights the utility of refining mobility understandings gained from integrated fluid and rock datasets and their relation to reservoir quality. We show two significant conclusions: 1) that comparing the extract geochemistry with rock properties can better define the cause and consequences of mobility trends and 2) that local data can be calibrated to regional geochemical trends of produced fluid, offering an inexpensive tool for predicting fluid mobility (and quality) away from control points. Signficant energy and cost has been applied to improve technology around understanding rock properties for better devlopment of resource plays, yet further work needs to be done to characterize and predict rock and fluid interactions to ultimately improve resource recovery. Data backed knowledge of rock/fluid interactions is required to build better models of flow behavior and better predict utlimate hydrocabron recovery.
- North America > United States > Wyoming (0.70)
- North America > United States > Texas (0.68)
- North America > United States > Colorado (0.48)
- North America > United States > Montana (0.45)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.68)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Abstract Understanding hydrocarbon mobility is crucial for forecasting petroleum production. Mobility assessment from traditional/legacy rock extraction techniques is challenged because light- to mid-chain hydrocarbons (LMHCs) of interest are not well preserved and are often lost prior to- or during sample analysis. Here, we build on advancements in sample handling procedures and new analytical laboratory techniques for a more detailed depiction of LMHC profiles as well as apply an innovative extraction technique on cores from the Williston, Powder River, Gulf Coast and Delaware Basins. We employ tailored thermal and chemical extraction techniques from whole core samples to characterize the recovered hydrocarbons as well as total water. By defining and delineating the hydrocarbon and water recovered by the two-step extraction workflow, mobility of fluids relative to the measured rock and fluid properties is better understood. Introduction An accurate understanding of fluids, including both water and hydrocarbons, in a prospective play is critical for economic development and eventual production. Legacy laboratory methods that attempt to i) quantify oil/water saturations, ii) correlate extracted organic matter from core back to produced fluids and/or iii) assess hydrocarbon mobility/producibility have success in limited basins/formations, but their shortcomings far outweigh their worth when a fully integrated rock and fluid approach is desired. For example, traditional extraction and quantification of water via crushed rock methodology from Dean-Stark methods (e.g. Luffel and Curtis 1996) has left operators with an overt underestimation of total water saturation (Swt) in liquid rich resource plays including the Permian Basin (Blount et al., 2017; Cheng et al., 2022). Underestimation of total water saturation can lead to widespread challenges between static in-place volumetric estimates versus physically produced water cuts in conventional and unconventional play opportunities. The underestimation of total water saturation can invoke error greater than 10-20% on in-place volumetric assessments. A reduction in error in combination with constraining additional parameters not addressed in this study (i.e. reservoir pressure, wettability, permeability, capillary pressure etc.), can close the gap between the in-place estimates and production forecasts and predictability.
- Geology > Petroleum Play Type > Unconventional Play (1.00)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
Time Lapse Geochemistry Production Allocation; End Member Definition and Selection; Case Studies, Delaware Basin and Eagle Ford
Turner, Adam (GeoMark Research) | Donohue, Catherine (GeoMark Research) | Zumberge, J. Alex (GeoMark Research) | Muñoz, Andrew (Ensign Natural Resources) | Bergeron, Philip (Ensign Natural Resources)
Abstract Allocation of production from hydraulically fractured wells in multi-target developments can be complex and challenging. While many tools help to model or approximate the extent of completions, geochemical analysis remains one of the most robust, inexpensive, and well-studied strategies. Time Lapse Geochemistry (TLG) is the chemical evolution of oils through time that provides insight into the extent of stimulated fracture networks. Two successful case studies, in the Delaware Basin and Eagle Ford trend, use TLG statistical models to support stratigraphically allocated commingled reservoir contributions to producing unconventional wells. Failure to account for geologic variability, analytical limits, and source and reservoir signatures can lead to misleading and costly allocations. Further, lack of recognition of what causes chemical variation beyond simply source facies leads to a lack of full application of the method. Given we can fully delineate flow units in multi-target developments using geochemical data, we can both unlock untapped intervals and optimize development strategy. We describe common pitfalls of TLG analysis and illustrate a successful TLG project that led to the identification of a substantial additional resource. INTRODUCTION In unconventional resource plays, it is common to simultaneously develop multiple stacked source and reservoir intervals. Using multi-targeted horizontal laterals, coupled with hydraulic fracturing stimulation, hydrocarbons are accessed within a large volume around each wellbore. However, geomechanical variations in stratigraphy limit the vertical and lateral extent of hydraulic fractures. These extents might not follow stratigraphy as mechanical barriers don't necessarily coincide with stratigraphically defined landing targets. Determining hydraulic fracture extents is challenging and usually involves a combination of 3D fracture modeling, geocellular modeling, and real-time pressure and fluid monitoring. Unfortunately, none of these cost-prohibitive methods will completely identify the short-term and long-term extents of hydraulic fracture stimulation in multi-target developments. We show, using two independent examples, how time-lapse geochemistry (TLG) is used to successfully allocate production to specific targets we define as flow units.
- 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)
- (36 more...)
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 300°C 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...)
Investigating Delaware Basin Bone Spring and Wolfcamp Observations Through Core-Based Quantification: Case Study in the Integrated Workflow, Including Closed Retort Comparisons
Perry, Stephanie E. (GeoMark Research Ltd.) | Zumberge, J. Alex (GeoMark Research Ltd.) | Cheng, Kai (GeoMark Research Ltd.)
The Delaware Basin of the greater Permian Basin system has been the focus of continually increased attention in the exploration, appraisal, and development phases of unconventional oil and gas potential over the past decade. While the industry continues to drill horizontal wells for the exploitation of producible hydrocarbon, subsurface disciplines continue to investigate the rock and fluid properties of the stratigraphy through the application of various technological tools. In this study, we focus on five wells spatially covering Loving, Ward, and Reeves Counties in West Texas, where whole core samples were acquired and investigated to compare variations in the Bone Spring and Wolfcamp Formations across varying geological contexts. Samples taken from the whole conventional core were investigated in the laboratory setting, and a series of measurements were acquired on each sample. The laboratory measurements distinguished trends and changes in the rock property volumes (i.e., porosity, saturation, total organic carbon) over stratigraphic intervals. The utilization of nuclear magnetic resonance, as well as acquired geochemical data, allows an innovative approach and application of a correction factor to be applied to the saturation quantification. Integration of geological context with measured laboratory data constraints and petrophysical wireline-log-based interpretation links predictive trends from the defined rock and fluid property distributions and may aid in predicting hydrocarbon vs. water production.
- North America > United States > New Mexico (1.00)
- North America > United States > Texas > Reeves County (0.24)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Geological Subdiscipline > Stratigraphy (0.91)
- 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)
- (26 more...)
- Well Drilling > Drilling Operations > Coring, fishing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (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 (1.00)
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 300°C 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...)
Abstract Subsurface characterization of fluid volumes is typically constrained and validated by core analytical fluid saturation measurement techniques (example Dean-Stark or Open Retort methodology). As production in resource plays has progressed over time, it has been noted that many of these methods have a large error when compared to production data. A large source of the error seems to be that water saturations in tight rocks have been consistently underestimated in the traditional laboratory measurement techniques. Operators need improved fluid saturation measurements to better constrain their log-based oil-in-place estimates and forward-looking production trends. The overall goal of this study is to test a new laboratory workflow for fluid saturation quantification. Recent advancements have led to an innovative methodology where a closed retort laboratory technique is applied to samples from lithological rock types in the Williston, Uinta and Denever-Julesburg (DJ) basins. This new technique is specifically designed to better quantify and validate water measurements throughout the tight rock analysis process, as well as improved oil recovery and built-in prediction. A comparison of standard crushed rock analysis employing Dean-Stark saturation methods is compared to the closed retort results and observations discussed. Results will also be compared against additional laboratory methods that validate the results such as geochemistry and nuclear magnetic resonance. Finally, open-hole wireline logs will be utilized to quantify the impact on total water saturation and the oil-in place estimates based on the improved accuracy of the closed retort technique.
- Research Report > New Finding (0.47)
- Overview > Innovation (0.34)
- Geology > Rock Type (1.00)
- Geology > Geological Subdiscipline > Stratigraphy (0.95)
- Geology > Geological Subdiscipline > Geochemistry (0.90)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.47)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > South Dakota > Williston Basin > Bakken Shale Formation (0.99)
- North America > United States > North Dakota > Williston Basin > Bakken Shale Formation (0.99)
- (8 more...)
Adaptation of Crushed Rock Analysis to Intact Rock Analysis for Improving Water Saturation Assessment and Fast Pressure Decay Permeability Quantification
Cheng, Kai (GeoMark Research Ltd) | Zumberge, J. Alex (GeoMark Research Ltd) | Perry, Stephanie E. (GeoMark Research Ltd) | Lasswell, Patrick M. (GeoMark Research Ltd)
Abstract 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 hydrocarbon 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 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 labs. The calculated pressure decay permeability of the same rock could even vary several orders of magnitude difference with different crushed size, 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 300 °C 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 grain volume measurement is then used for calculating pressure decay matrix permeability. Total porosity is calculated using bulk volume and grain volume of the rock. Water saturation is quantified using 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, pressure decay permeability is cross-validated against the steady state permeability of the same sample. The introduced workflow has been successfully tested 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 average 8%SU (0.2–0.7%PU of bulk volume water) higher than those from the prior crushed rock workflow. The study also indicated that for some formations (e.g., Bone Spring) the fluid loss during crushing process is dominated by water, however, for some other formations (e.g., Bakken), 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.
- Research Report > New Finding (0.88)
- Research Report > Experimental Study (0.66)
- Geology > Rock Type > Sedimentary Rock (0.69)
- Geology > Geological Subdiscipline > Geochemistry (0.68)
- North America > United States > Wyoming > Wind River Basin > NPR-3 > Muddy Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.93)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.93)
- (11 more...)