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Compositional Fractionation of Petroleum Fluids During Migration and Production: A Bakken Case Study with Fourier Transform Ion Cyclotron Resonance (FT-ICR) Mass Spectrometry
Song, Yishu (ConocoPhillips) | Michael, Eric (ConocoPhillips) | McLin, Kristie (ConocoPhillips) | Mahlstedt, Nicolaj (GFZ German Research Centre for Geosciences) | Horsfield, Brian (GFZ German Research Centre for Geosciences) | Potz, Stefanie (GFZ German Research Centre for Geosciences) | Mangelsdorf, Kai (GFZ German Research Centre for Geosciences)
Abstract Petroleum fractionation during migration and production is the progressive compositional change as petroleum fluids migrate through or are produced from porous media. This study employed Fourier Transform Ion Cyclotron Resonance mass spectrometry (FT-ICR-MS) coupled with atmospheric pressure photoionization (APPI) to study the heavy end compositional differences of in-situ oils across Bakken and Three Forks Formations at a single well location and nearby produced oils from Middle Bakken and Three Forks. Profound fractionation is evidenced in both hydrocarbons and non-hydrocarbons as migration and production proceed: 1) compositional complexity decreases; 2) non-hydrocarbon content decreases whilst hydrocarbon content increases correspondingly; 3) compounds with higher aromaticity lag behind; 4) co-variation patterns are discernible among different compounds and indicate polarity and aromaticity exert a larger influence on fractionation than molecular weight. Improved understanding of migration and production fractionation in the context of formation rock minerology, formation water and completion fluids chemistry, and reservoir PT conditions assists in optimizing completion and production and developing play-specific enhanced oil recovery technologies. Introduction Petroleum fractionation during migration and production, also known as geo-chromatographic effect, refers to the progressive compositional change as petroleum fluids migrate through or are produced from porous media. Such fractionation has long been observed yet remains challenging to predict, as it involves the interplay of a myriad of mechanisms, like differential partitioning of compounds between gas, oil and water phases and selective retention by minerals (Thompson, 1987, Thompson, 1988, Leythaeuser et al., 1988, Dzou, 1993, Later, 1996). To a certain degree, PVT simulation can be utilized to model the bulk compositional changes as fluids migrate to shallower strata or as a reservoir depletes, especially in the light ends (Larter et al., 1991, England, 2002). However, PVT modeling misses the majority of geochemical changes due to interactions of petroleum fluids with formation rocks, formation water, and completion fluids. While changes in fluids bulk properties, like API gravity, resulting from the fractionation are readily detectable, the underlying geochemical changes can be difficult to determine, particularly in the heavy end with a large portion of polar compounds not amenable to GC based analyses. This study employed Fourier Transform Ion Cyclotron Resonance mass spectrometry (FT-ICR-MS) coupled with atmospheric pressure photoionization (APPI) to investigate the heavy end compositional differences of in-situ oils (core extracts) across Bakken and Three Forks Formations at a single well location and produced oils from nearby horizontal wells landed in the Middle Bakken and Three Forks (Robb et al., 2000, Purcell et al., 2007, Marshall, 2008, Han et al., 2020). Profound fractionation is manifested in both hydrocarbons (compounds containing only H can C) and non-hydrocarbons (compounds containing heteroatoms like O, N, S besides H and C) as migration and production proceed. Left behind during migration and production, heavy and polar petroleum compounds modify formation rock wettability and permeability and affect subsequent migration and production efficacies, particularly in plays with low porosity and permeability. Improved understanding of migration and production fractionation in the context of formation rock minerology, formation water and completion fluids chemistry, and reservoir PT conditions assists in optimizing completion and production and developing play-specific enhanced oil recovery technologies.
- North America > United States > North Dakota (1.00)
- North America > United States > Texas > Harris County > Houston (0.28)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.71)
- North America > United States > South Dakota > Williston Basin > Bakken Shale Formation (0.99)
- North America > United States > Montana > Williston Basin > Bakken Shale Formation (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > South Viking Graben > Block 16/7a > Brae Field > Brae Formation (0.99)
- (32 more...)
Fine-Scale Lamination/Bedding, An Important Factor in Unconventional Reservoirs Hydrocarbon Productivity
Molinares-Blanco, Carlos (IRC, The University of Oklahoma) | Becerra-Rondon, D. (IRC, The University of Oklahoma / University of Calgary) | Galvis-Portilla, H. (IRC, The University of Oklahoma / University of Calgary) | Duarte, D. (IRC, The University of Oklahoma / Ovintiv)
Abstract The fine-scale lamination/bedding is an important feature commonly neglected in the characterization of unconventional reservoirs. Self-sourced mudstone deposits are frequently described as layered, or Vertical Transverse Isotropic (VTI) bodies, assuming the absence of significant vertical discontinuities (faults, fractures, cracks, etc.) Fine lamination/bedding is below the standard well log tool's and that affect reservoir petrophysical properties calculated from logs, such as porosity, pay, oil saturation, and geomechanical properties based on sonic and density logs, such as Brittleness, Young's Modulus or Poisson's Ratio. The understanding of lamination/bedding is a key element to define the best intervals for hydraulic fracturing, because rock fabric may significantly improve productivity due three main reasons: 1) More laminae within brittle intervals may act as weak planes that help to reduce the effective minimum horizontal stress. 2) Multi-layered reservoirs have a better storage capacity (thickness and porosity), commonly underestimated in conventional well logs. 3) The interbedding between organic-rich ductile beds (i.e., source rock) and organic-lean brittle beds (i.e., reservoir, carriers) may facilitate the hydrocarbon expulsion, because of a higher contact surface. Introduction The Woodford Shale and the overlying Mississippian units are one of the most prolific unconventional plays in North America. A total of 22 billion barrels of bitumen and 16 billion barrels of saturated hydrocarbons expelled from the Woodford, only from the central and southern areas in Oklahoma (Comer and Hinch, 1987). Recently, the production and activity in Oklahoma are concentrated mainly in the STACK and SCOOP areas in the Anadarko Basin. The area of interest in this study was a portion of the Grady, County (Figure 1). In this work, a specific completion campaign of 11 horizontal wells drilled at Grady County (2014-2015) were analyzed (Figure 2). The unconventional wells performance is commonly influenced by a combination of in situ rock properties and completion parameters (Sayers et al., 2015), but in this case (Figure 3), the completion parameter including numbers of stages, type and amounts of proppant and liquids were very similar and designed by the same oil company operator (After, Molinares et al., 2017) Figure 1. Cumulative gas production by Township @Dec 2018 (Source HIS). Red rectangle represents Grady County, area of interest and pie chart represent changes in oil(green)/gas(red) ratio productions.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.31)
- North America > United States > Texas > Anadarko Basin (0.99)
- North America > United States > Kansas > Anadarko Basin (0.99)
- North America > Canada > British Columbia > Western Canada Sedimentary Basin > Horn River Basin (0.99)
- (32 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
During well planning, drillers and petrophysicists have different principle objectives. The petrophysicist’s aim is to acquire critical well data, but this can lead to increased operational risk. The driller is focused on optimizing the well design, which can result in compromised data quality. In extreme cases, the impact of well design on petrophysical data can lead to erroneous post-well results that impact the entire value-chain assessment and decision making toward field development. This paper presents a case study from an Upper Jurassic reservoir in the Norwegian Sea where well design significantly impacted reservoir characterization. Three wells (exploration, appraisal, and geopilot) are compared to demonstrate the impact of overbalanced drilling on both log and core data. Implications for reservoir quality assessment and volume estimates are discussed. Extensive data collection was initially carried out in both exploration and appraisal wells, including full sets of logging while drilling (LWD), wireline logging, fluid sampling, and extensive coring. Both wells were drilled with considerable overbalanced mud weights due to the risk of overpressured reservoirs in the region. The log data were subsequently corrected for significant mud-filtration and fines invasion, with calibration to core measurements guiding the interpretation. A thorough investigation of core material raised suspicion that there could also be significant adverse effects on core properties resulting from overbalanced drilling. The implications were so significant for the reservoir volume that a strategic decision was made to drill a geopilot well close to the initial exploration well prior to field development drilling. The well was drilled 6 years after the initial exploration phase with considerably lower overbalance. Extensive well data, including one core, were acquired. The recovered core was crucial in order to compare the reservoir properties for comparable facies between all three wells. The results from the core demonstrate distinctly different rock quality characteristics, especially at the high end of the reservoir quality spectrum. Results of the core study confirmed the initial hypothesis that overbalanced drilling had significantly impacted the properties of the core and well logs. This study shows how well design adversely affected petrophysical measurements and how errors in these data compromised geological and reservoir models, leading to a suboptimal field development plan that eroded significant value. This example provides a case study that can be used to improve well designs so that petrophysicists and drillers can both be part of the same value creation result.
- North America > United States (1.00)
- Asia (0.68)
- Europe > United Kingdom > North Sea (0.46)
- Europe > Norway > North Sea (0.46)
- Geology > Sedimentary Geology (1.00)
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline > Geomechanics (0.69)
- (2 more...)
- Geophysics > Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Europe > United Kingdom > North Sea > Central North Sea > South Viking Graben > Block 16/7a > Brae Field > Brae Formation (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > South Viking Graben > Block 16/3b > Brae Field > Brae Formation (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > South Viking Graben > Block 16/3a > Brae Field > Brae Formation (0.99)
- (12 more...)
Abstract During well planning, drillers and petrophysicists have different principle objectives. The petrophysicist’s aim is to acquire critical well data, but this can lead to increased operational risk. The driller is focused on optimizing the well design, which can result in compromised data quality. In extreme cases, the impact of well design on petrophysical data can lead to erroneous post-well results that impact the entire value-chain assessment and decision making toward field development. In this paper, we present a case study from a syn-rift, Upper Jurassic reservoir in the Norwegian Sea where well design significantly impacted reservoir characterization. Three wells (exploration, appraisal, and geopilot) are compared in order to demonstrate the impact of overbalanced drilling on well data from both logs and core. Implications for reservoir quality assessment, volume estimates, and the errors introduced into both a static geomodel and dynamic reservoir simulation are discussed. This case study highlights the importance of optimizing well design for petrophysical data collection and demonstrates the potential for value creation. Extensive data collection was initially carried out in both exploration and appraisal wells, including full sets of logging while drilling (LWD), wireline logging, fluid sampling, and extensive coring. Both wells were drilled with considerable overbalanced mud weights due to the risk of overpressured reservoirs in the region. The log data was subsequently corrected for significant mud-filtration invasion, with calibration to core measurements guiding the interpretation. Geological and reservoir models were built based on results from the two wells, and development wells were planned accordingly. A thorough investigation of core material raised suspicion that there could also be a significant adverse effect of core properties resulting from overbalanced drilling. The implications were so significant for the reservoir volume that a strategic decision was made to drill a geopilot well close to the initial exploration well, prior to field development drilling. The well was drilled six years after the initial exploration phase with considerably lower overbalance. Extensive well data, including one core, were acquired. The recovered core was crucial in order to compare the reservoir properties for comparable facies between all three wells. The results from the core demonstrate distinctly different rock quality characteristics, especially at the high end of the reservoir quality spectrum. Results of the core study confirmed the initial hypothesis that overbalanced drilling had significantly impacted the properties of the core as well as the well logs. The study concluded that the updated reservoir model properties would significantly increase the in-place volumes compared to the pre-geopilot estimate. This study shows how well design adversely affected petrophysical measurements and how errors in these data compromised geological and reservoir models, leading to a suboptimal field development plan that eroded significant value. This example provides a case study that can be used to improve the well design so that petrophysicists and drillers can both be part of the same value creation result. Future work will include further laboratory investigations on the effects of high overbalanced drilling on core and possible “root causes” for compromised core integrity.
- Geology > Sedimentary Geology (1.00)
- Geology > Mineral (1.00)
- Geology > Structural Geology > Fault (0.93)
- (3 more...)
- Europe > United Kingdom > North Sea > Central North Sea > South Viking Graben > Block 16/7a > Brae Field > Brae Formation (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > South Viking Graben > Block 16/3b > Brae Field > Brae Formation (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > South Viking Graben > Block 16/3a > Brae Field > Brae Formation (0.99)
- (8 more...)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- (2 more...)
Summary In this paper we present a method for identifying intervals in shale oil reservoirs that contain moveable hydrocarbons with a novel geochemical productivity index (PI), . This index merges three important rock properties that must always be considered for sound shale oil reservoir characterization: vitrinite reflectance (), oil–saturation index (OSI), and free–water porosity (). Integrating this index with other petrophysical properties and geomechanical parameters defines intervals with high moveable oil content. Shale oil is both a source rock and an unconventional reservoir rock. Hence, it is critical to know both its organic–matter (OM) maturity and its oil/water flow capacity. The introduced considered these features simultaneously; maturity was evaluated by discretizing from 0 to 1, depending on whether the rock was immature or not; free oil flow capacity modeled the normalizing between 0 and 1 on the basis of results from the Rock-Eval VI pyrolysis (REP) obtained in the laboratory or by electric logs; and water flow capacity was estimated from , obtained using a nuclear–magnetic–resonance (NMR) log, which was transformed into an index between 0 and 1. Flow oil capacity was defined as the amount of moveable oil that exceeded the sorption capacity of the source rock. Using the is explained with real data from a vertical well that penetrates several stacked shale oil reservoirs. However, the same approach can be used in any other type of wellbore architecture (i.e., deviated, horizontal, geosteered). Initially, a correlation between vertical depth and was developed. This resulted in a continuous OM–maturity curve along the well section. Next, OSI was simulated by using a bin porosity from an NMR log, where was between 33 and 80 milliseconds and was correlated with OSI data from REP. As a result, a good match between the simulated and the real OSI data was achieved. Similar to OSI, was also calculated from the NMR log, but it used a bin porosity when was greater than 80 milliseconds. These three parameters were then transformed to fractional indices, which were combined into a unique index, . When the index was greater than 0.66, there was a good chance that the three conditions mentioned above would be met. For the example well considered in this study, it was found that almost 30% of the total vertical section had good moveable oil potential. This corresponded to 10 intervals in the well. The key novelty of this paper is that we have developed a continuous curve of an index that is easy to use and is powerful for identifying intervals with moveable hydrocarbon potential. This is true even in those intervals without laboratory data because of the continuity of the curve, in addition to the integrated criteria that are usually applied independently. The Igp index is a simple–to–use approach. However, because it is a new method, an explorationist should validate it against real oil production information.
- Europe (1.00)
- North America > United States > Texas (0.93)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
Non-Chemical Methods for Downhole Control of Carbonate and Sulphate Scales - An Alternative Approach to Scale Management?
Heath, Stephen (Baker Hughes a GE Company) | Bin Ruslan, Mohd Zahirin (Baker Hughes a GE Company) | McKay, Eric (Baker Hughes a GE Company) | Ishkov, Oleg (Baker Hughes a GE Company)
Abstract The deposition of carbonate and sulphate scales is a major problem during oil and gas production. Managing scale with chemical application methods involving either scale prevention and/or removal are the preferred methods of maintaining well production. However, chemical scale control is not always an option, depending upon the nature of the reservoir and well completion and, in cases of severe scaling, the problem can render chemical treatments uneconomic unless other non-chemical methods are utilised. A variety of non-chemical scale control methods exist, the most common being injection of low salinity brines or low sulphate seawater (LSSW) using reverse osmosis and a sulphate removal plant (SRP) respectively. In addition, careful mixing of lift gas, produced waters and reinjection, coatings, smart well completions with active inflow control devices (ICD) and sliding sleeves (SS) are other methods. All of these techniques, including combinations thereof, are currently in use and the advantages and disadvantages of the key techniques are compared to chemical methods for both carbonate and sulphate scale control. A detailed example from a North Sea field demonstrates where downhole chemical scale control has not been required through a strategy of careful mixing of lift gas, brines and produced water re-injection. This was combined with understanding fluid flow paths in the reservoir and their likely breakthrough at production wells. Consideration is given to the injection of smart brines to scale deep in the reservoir, and data from North Sea chalk fields shows how "in situ" geochemical reactions between the reservoir and the injected fluid can precipitate sulphate scales. The necessity to understand these geochemical reactions and their implications for improved oil recovery and the design of smart injection brines for scale control are discussed. This paper presents a comprehensive review of non-chemical methods for downhole scale control and discusses how the use of these techniques can provide alternative scale management strategies through minimising or alleviating the need for downhole chemical treatments.
- Europe > United Kingdom > North Sea (0.55)
- Europe > Norway > North Sea (0.55)
- Europe > Denmark > North Sea > Danish Sector (0.28)
- Geology > Mineral > Sulfate (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Limestone (0.35)
- Europe > United Kingdom > North Sea > Central North Sea > South Viking Graben > Block 16/7a > Brae Field > Brae Formation (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > South Viking Graben > Block 16/3b > Brae Field > Brae Formation (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > South Viking Graben > Block 16/3a > Brae Field > Brae Formation (0.99)
- (23 more...)
- Well Completion > Completion Monitoring Systems/Intelligent Wells (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Production and Well Operations > Well Operations and Optimization (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
Streamline Simulation of Barium Sulfate Precipitation Occurring Within the Reservoir Coupled With Analyses of Observed Produced-Water-Chemistry Data To Aid Scale Management
Hu, Yisheng (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Mackay, Eric (Heriot-Watt University) | Vazquez, Oscar (Heriot-Watt University) | Ishkov, Oleg (Heriot-Watt University)
Summary In waterflooded reservoirs under active scale management, produced-water samples are routinely collected and analyzed, yielding information on the evolving variations in chemical composition. These produced-water chemical-composition data contain clues as to the fluid/fluid and fluid/rock interactions occurring in the subsurface, and are used to inform scale-management programs designed to minimize damage and enable improved recovery. In this interdisciplinary paper, the analyses of produced-water compositional data from the Miller Field are presented to investigate possible geochemical reactions taking place within the reservoir. The 1D and 2D theoretical model has been developed to test the modeling of barium sulfate precipitation implemented in the streamline simulator FrontSim. A completely 3D streamline simulation study for the Miller Field is presented to evaluate brine flow and mixing processes occurring in the reservoir by use of an available history-matched streamline reservoir-simulation model integrated with produced-water chemical data. Conservative natural tracers were added to the modeled injection water (IW), and then the displacement of IW and the behaviors of the produced water in two given production wells were studied further. In addition, the connectivity between producers and injectors was investigated on the basis of the comparison of production behavior calculated by the reservoir model with produced-water chemical data. Finally, a simplified model of barite-scale precipitation was included in the streamline simulation, and the calculation results with and without considering barite precipitation were compared with the observed produced-water chemical data. The streamline simulation model assumes scale deposition is possible everywhere in the formation, whereas, in reality, the near-production-well zones were generally protected by squeezed scale inhibitor, and, thus, the discrepancies between modeled and observed barium concentrations at these two given wells diagnose the effectiveness of the chemical treatments to prevent scale formation.
- Europe > United Kingdom > North Sea > Central North Sea (1.00)
- Europe > Norway (1.00)
- Asia (1.00)
- North America > United States > Texas (0.93)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.46)
- Geology > Mineral > Sulfate > Barite (0.46)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.46)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (0.35)
- Europe > United Kingdom > North Sea > Central North Sea > South Viking Graben > Blocks 16/7b > Miller Field (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > South Viking Graben > Block 16/8b > Miller Field (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > South Viking Graben > Block 16/7a > Brae Field > Brae Formation (0.99)
- (21 more...)
- Reservoir Description and Dynamics > Reservoir Simulation > Streamline simulation (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Health, Safety, Environment & Sustainability > Environment > Water use, produced water discharge and disposal (1.00)
Abstract A technical-economic research was done evaluating microfiltration polymeric membranes and cartridge filters as pretreatment of Sulfate Removal Units (SRU). These units were installed in a Stationary Production Unit (SPU) to reduce the concentration of sulfate from seawater (injection water in Enhanced Oil Recovery). The use of seawater with low sulfate in enhanced oil recovery reduces the risk of sulfate deposits during the oil production. Ten companies from different nationalities involved in the industrial water treatment and manufacturing of polymeric membranes sector, have contributed to this comparative research (only a preliminary stage of the future study with qualitative and quantitative analyses). This paper shows that polymeric microfiltration is more advantageous because reduce operational costs and microbiological contamination resulting in a lower risk of biofouling. It also improves the quality of treated water, increases the operational stability and availability of the injection water, extending the lifetime of the nanofiltration polymeric membranes.
- North America > United States > Colorado (0.29)
- South America > Brazil > Rio de Janeiro (0.29)
- Water & Waste Management > Water Management > Lifecycle > Reclamation (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Europe > United Kingdom > North Sea > Central North Sea > South Viking Graben > Block 16/7a > Brae Field > Brae Formation (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > South Viking Graben > Block 16/3b > Brae Field > Brae Formation (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > South Viking Graben > Block 16/3a > Brae Field > Brae Formation (0.99)
Plugging and Abandonment of Oil and Gas Wells: A Geomechanics Perspective
Davison, J. M. (Shell Global Solutions International B.V.) | Salehabadi, M. (Shell UK Exploration & Production) | De Gennaro, S. (Shell UK Exploration & Production) | Wilkinson, D. (Shell UK Exploration & Production) | Hogg, H. (Shell UK Exploration & Production) | Hunter, C. (Shell UK Exploration & Production) | Schutjens, P. (Shell Global Solutions International B.V.)
ABSTRACT: At the end of field life, wells require permanent plugging and abandonment (P&A) as part of decommissioning activities. Some UK fields developed in the 1970’s are reaching their end of field life, with UK industry estimates predicting well P&A costs over the next 30-40 years of 24 billion dollars. As well as the high financial cost, there is a significant HSSE exposure to ensure safe and reliable P&A such that no escape of hydrocarbons is possible to the near surface environment.
- North America > United States (1.00)
- Europe > Norway (0.71)
- Europe > United Kingdom > North Sea > Central North Sea (0.47)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.34)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 211/29 > Brent Field (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > South Viking Graben > Block 16/8a > Kingfisher Field > Brae Formation (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Block 22/30b > Shearwater Field > Fulmar Formation (0.99)
- (15 more...)
Geochemical evidence for oil and gas expulsion in Triassic lacustrine organic-rich mudstone, Ordos Basin, China
Zhang, Tongwei (The University of Texas at Austin) | Wang, Xiangzeng (Shaanxi Yanchang Petroleum (Group) Co. Ltd.) | Zhang, Jianfeng (Shaanxi Yanchang Petroleum (Group) Co. Ltd.) | Sun, Xun (The University of Texas at Austin) | Milliken, Kitty L. (The University of Texas at Austin) | Ruppel, Stephen C. (The University of Texas at Austin) | Enriquez, Daniel (The University of Texas at Austin)
Abstract Forty-six core samples were collected from a deep well that penetrated organic-rich layers of the Chang 7, 8, and 9 members of the Yanchang Formation (Fm) in the Ordos Basin. Tests for total organic content (TOC), Rock-Eval pyrolysis, X-ray diffraction (XRD) mineralogy, and molecular composition of gases released from rock crushing were conducted. Analytical results indicate that TOC and clay contents are elevated. The organic matter (OM)-rich mudstone in the Triassic Yanchang Fm suggests good-to-excellent source potential for oil generation. Its thermal maturity is in the oil window. Strong petroleum expulsion occurred from the upper part of the approximately 13 m (42.6 ft) thick Chang 7 member, and for the Chang 8 and Chang 9 members, resulting in low free oil and low methane () concentration in these OM-rich intervals. A combination of sandstone and thin organic-rich mudstone layers is a perfect hybrid lithology stacking pattern for petroleum expulsion. The thickness for effective source rock, approximately 10–12 m (32.8–39.3 ft), varied with sandstone/mudstone lithology stacking pattern. In contrast, limited or no oil expulsion occurred in the lower part of Chang 7 member, a 25 m (82 ft) thick organic-rich interval, which is indicated by high free oil and high concentration. A -TOC plot can be used to differentiate generated gas, retained gas in OM-rich mudstones, and migrated gas in permeable sandstone beds. We have developed a conceptual model for petroleum expulsion from OM-rich thin versus OM-rich thick layers. Compaction and thermal volume expansion of oil generated from OM may play an important role in petroleum expulsion in OM-rich mudstones. The estimated petroleum expulsion efficiency is approximately 70% and 35% for thin and thick OM-rich mudstone layers, respectively. The redistributed OM in clay-dominated rock assemblage likely forms the preferred migration path to petroleum expulsion.
- North America > United States > Texas (1.00)
- Asia > China > Shaanxi Province (0.71)
- Asia > China > Gansu Province (0.71)
- Asia > China > Shanxi Province (0.61)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.71)
- 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)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (11 more...)