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Collaborating Authors
Results
NanoGram Detection of Drilling Fluids Additives for Uncertainty Reduction in Surface Logging
Zhu, S. Sherry (Aramco Research Center – Boston, 400 Technology Square, Cambridge, MA) | Antoniv, Marta (Aramco Research Center – Boston, 400 Technology Square, Cambridge, MA) | Poitzsch, Martin (Aramco Research Center – Boston, 400 Technology Square, Cambridge, MA) | Aljabri, Nouf (Saudi Aramco, EXPEC ARC, Dhahran, Saudi Arabia) | Marsala, Alberto (Saudi Aramco, EXPEC ARC, Dhahran, Saudi Arabia)
Abstract Manual sampling rock cuttings off the shale shaker for lithology and petrophysical characterization is frequently performed during mud logging. Knowing the depth origin where the cuttings were generated is very important for correlating the cuttings to the petrophysical characterization of the formation. It is a challenge to accurately determine the depth origin of the cuttings, especially in horizontal sections and in coiled tubing drilling, where conventional logging while drilling is not accessible. Additionally, even in less challenging drilling conditions, many factors can contribute to an inaccurate assessment of the depth origin of the cuttings. Inaccuracies can be caused by variation of the annulus dimension used to determine the lag time (and thus the depth of the cuttings), by the shifting or scrambling of cuttings during their return trip back to the surface, and by the mislabelling of the cuttings during sampling. In this work, we report the synthesis and application of polystyrenic nanoparticles (NanoTags) in labeling cuttings for depth origin assessment. We have successfully tagged cuttings using two NanoTags during a drilling field test in a carbonate gas well and demonstrated nanogram detection capability of the tags via pyrolysis-GCMS using an internally developed workflow. The cuttings depth determined using our tags correlates well with the depth calculated by conventional mud logging techniques.
- Geology > Rock Type (0.68)
- Geology > Geological Subdiscipline > Geochemistry (0.35)
Abstract One of the harms to climate brought about by anthropogenically instigated environmental change is the overabundance creation of CO2 because of industrialization. Research and development endeavors so far have been focused on the improvement of CCS (Carbon Capture and Sequestration), with the fundamental spotlight on the best way to eliminate CO2 from vent gases and how to cover it perpetually in deep aquifers or depleted oil and gas reservoirs to save the environment from the detrimental effects of CO2. At one side, the alarming situation due to excess emission of CO2 from industries has been bulled out and simultaneously, there is higher potential for CO2 in the depleted oil fields which can aid to the Enhanced Oil Recovery (EOR) through the prolonged CO2 injection in depleted oil fields. It is currently turning out to be certain that CCS technology could advance the utilization of fossil fuels than in any case recently thought. This paper discusses the integration of Carbon Capture and Sequestration (CCS) technology with the progressive strategy of Enhanced Oil Recovery (EOR). CCS includes various advances that can be utilized to catch CO2 from point sources. Countries that are badly affected by the harmful effects of global warming with depleting oil reserves in the very near future can be the most viable target of the CCS Project. The scope and potential of different techniques of CCS along with the opportunities and challenges and the real case scenarios happening in the world are discussed in detail. The economics, process cycle and case studies of this futuristic technology intend to give valuable insight to the implementation of this integrated technique to the prevalent depleting oil fields around the globe.
- Asia (0.94)
- North America > Canada > Alberta (0.48)
- North America > United States > Texas (0.30)
- North America > United States > Texas > Permian Basin > Central Basin > Wasson Field > Wolfcamp Formation (0.99)
- North America > United States > Texas > Permian Basin > Central Basin > Wasson Field > Wichita Albany Formation (0.99)
- North America > Canada > Alberta > Athabasca Oil Sands > Western Canada Sedimentary Basin > Alberta Basin > Athabasca Oil Sands Project (0.99)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Health, Safety, Environment & Sustainability > Environment > Climate change (1.00)
- Data Science & Engineering Analytics > Information Management and Systems (1.00)
Abstract One of the typical production challenges is occurrence of impermeable layers of highly viscous asphaltenic oil (known as tarmat) at oil/water contact within a reservoir. Tar forms a physical barrier that isolates producing zones from aquifer or water injectors. As a result of tar occurrence, is a rapid pressure decrease that can be observed in such reservoirs, increasing number of dead wells, and declining productivity. Another indirect consequence of Tar presence is poor sweep efficiency that leads to water cut increase by a drastic magnitude. An innovative approach was developed to establish better sweep efficiency, transmissibility and pressure maintenance of Tar impacted-areas using thermochemical treatment. The treatment consists of injecting exothermic reaction-components that react downhole and generate in-situ pressure and heat. The in-situ reaction products provide heat and gas-drive energy to mobilize tar, improve sweep efficiency and maintain flooding for better pressure maintenance. Typically, downhole heat generation through chemical reaction releases substantial heat which could be employed in various thermal stimulation operations. Nano/ionic liquids, high pH solutions, solvents and nano metals were combined with the exothermic reaction to improve tar mobilization. Based on lab testing, the new technology showed more recovery than conventional steam flooding. Permeable channels were created in a tar layer with sandback samples, which enhanced transmissibility, pressure support and sweep efficiency. The effect of thermochemical treatment and ionic liquid on bitumen texture will be described. Impact of In-situ generated heat on injectivity will also be presented. The novel method will enable commercial production from tar-impacted reservoirs, and avoid costly steam flooding systems. The developed novel treatment relates to in-situ steam generation to maximize heat delivery efficiency of steam into the reservoir and to minimize heat losses due to under and/or over burdens. The generated in-situ steam and gas can be applied to recover deep oil reservoirs, which cannot be recovered with traditional steam, miscible gas, nor polymer injection methods.
- Asia > Middle East > Saudi Arabia (0.70)
- North America (0.69)
- Research Report > New Finding (0.69)
- Overview > Innovation (0.55)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.70)
- Geology > Geological Subdiscipline > Geochemistry (0.46)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.36)
Production Performance Analysis of Western Siberia Mature Waterflood with Prime Diagnostic Metrics
Aslanyan, Arthur (Nafta College) | Margarit, Andrey (Gazpromneft STC) | Popov, Arkadiy (Gazpromneft STC) | Zhdanov, Ivan (Gazpromneft STC) | Pakhomov, Evgeniy (Gazpromneft STC) | Garnyshev, Marat (Sofoil) | Gulyaev, Danila (Sofoil) | Farakhova, Rushana (PolyKod)
Abstract The paper shares a practical case of production analysis of mature field in Western Siberia with a large stock of wells (> 1,000) and ongoing waterflood project. The main production complications of this field are the thief water production, thief water injection and non-uniform vertical sweep profile. The objective of the study was to analyse the 30-year history of development using conventional production and surveillance data, identify the suspects of thief water production and thief water injection and check the uniformity of the vertical flow profile. Performing such an analysis on well-by-well basis is a big challenge and requires a systematic approach and substantial automation. The majority of conventional diagnostic metrics fail to identify the origin of production complications. The choice was made in favour of production analysis workflow based on PRIME metrics, which automatically generates numerous conventional production performance metrics (including the reallocated production maps and cross-sections) and additionally generates advanced metrics based on automated 3D micro-modelling. This allowed to zoom on the wells with potential complications and understand their production/recovery potential. The PRIME analysis has also helped to identify the wells and areas which potentially may hold recoverable reserves and may benefit from additional well and cross-well surveillance.
- Asia (1.00)
- Europe (0.94)
- North America > United States (0.93)
- Oceania > Papua New Guinea > Papuan Peninsula > Central Province > National Capital District > Petroleum Retention License 15 > P’nyang Field (0.97)
- Oceania > Papua New Guinea > Papuan Peninsula > Central Province > National Capital District > Petroleum Retention License 15 > Elk-Antelope Field (0.97)
- Oceania > Papua New Guinea > Papuan Peninsula > Central Province > National Capital District > Petroleum Retention License 15 > Angore Field (0.97)
- (9 more...)
An Experimental Investigation of the Effect of Changing the Rock's Wettability on the Performance of Carbonated Water Injection CWI
Castaneda, Jaime Orlando (Heriot Watt University) | Alhashboul, Almohannad (Heriot Watt University) | Farzaneh, Amir (Heriot Watt University) | Sohrabi, Mehran (Heriot Watt University)
Abstract CWI is affected by multiple factors, including the wettability of the rock. These experiments seek to determine the results that are obtained when CW is injected in a tertiary mode for systems: (1) wetted by water and (2) mixed wettability; to date, no study has used this approach. The same sandstone core was used in all trials, and each test consisted of saturating the core with live crude, followed by the injection of water as a secondary recovery and then the injection of CW as a tertiary recovery. An additional sensitivity test was conducted that consisted of varying the composition of the dissolved gas in the crude. In general, in a water wet system, the recovery associated with the injection of CW is higher (normalized) compared to a mixed wettability system. This does not mean that the results were negative in the mixed system. On the contrary, the results are positive since on the order of an additional 20% was recovered. However, the pressure differential in a mixed system is higher (14%) compared to water wet system. Although it is common knowledge that wettability of the rock affects the production and pressure results in an experiment, these are the first experiments that have been performed exclusively to determine quantitatively the response to CWI while maintaining the other parameters constant.
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.87)
Pilot Project: Application of Multi-Component Thermal Fluid Stimulation on Shallow Heavy Oil Reservoir in Kazakhstan
Yi, Leihao (China Petroleum Technology & Development Corporation, CNPC) | Hua, Xin (China Petroleum Technology & Development Corporation, CNPC) | Guan, Wenlong (Research Institute of Petroleum Exploration & Development, PetroChina Co. Ltd.) | Xu, Shiguo (CNPC Global Solutions Ltd.) | Zhang, Ziyi (Beijing Unobstruct Petroleum technology Service Co.) | Mei, Yizhong (Beijing Unobstruct Petroleum technology Service Co.) | Guo, Erpeng (Research Institute of Petroleum Exploration & Development, PetroChina Co. Ltd.) | Liu, Junping (China Petroleum Technology & Development Corporation, CNPC) | Zhong, Li (China Petroleum Technology & Development Corporation, CNPC) | Liu, Guohui (China Petroleum Technology & Development Corporation, CNPC) | Zheng, Xiantao (China Petroleum Technology & Development Corporation, CNPC) | Wei, Zhen (China Petroleum Technology & Development Corporation, CNPC)
Abstract Cyclic steam simulation (CSS) was widely used to recover heavy oil in shallow reservoirs in Kazakhstan. In the late stage of CSS in M oilfield, the performance of this CSS project was poor with high water cut and low oil steam ratio (OSR), indicating low economic benefit. The multi-component thermal fluid (MTF) stimulation trial has been conducted there since March 2018 to evaluate the feasibility of this technology. This paper introduces the field experience and the production performance of MTF stimulation. Results are from 32 cycles of MTF stimulations in 23 wells, most of which had completed their 4 cycles of CSS before. MTF technology is based on a high-pressure jet combustion mechanism, generating a mixture of nitrogen, carbon dioxide and vapor (MTF) under a sealed combustion condition. The mixture fluid provides a significant enhancement through a synergistic effect in the reservoir. The soaking and recovery process are the same as the conventional steam stimulation, meanwhile the requirements for completion and wellbore structure are the same as well. By the time of statistic, average cyclic OSR reaches 2.19 from 0.49 of last CSS cycle. Average water cut declines from 90% to 40% and daily oil production rises from 22 bbls to 33 bbls. Free water is almost invisible in the produced fluid, instead, a stable quasi-monophasic flow has been presented even at low temperatures. This effectively increases the fluidity and dilatancy of crude oil, and greatly replenishes the elastic energy of the formation. Meanwhile, with all components injected into the formation, MTF stimulation achieves significant reduction in carbon emissions. Although this is a pilot test, considerable economic benefits have been achieved with the increase of oil production efficiency. MTF stimulation brings an additional profit of USD 4.4 million for the first year under conditions of local material's cost. This successful pilot demonstrates that MTF stimulation may play an important role at late stage of CSS, even it has its own prospect in an initial heavy oil reservoir development. In the meantime, this pilot experience can be used as a reference for other similar reservoirs’ development.
- Asia > China (0.72)
- Asia > Kazakhstan (0.61)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Conformance improvement (1.00)
Abstract In recent years, numerical fracturing simulation has seen an unprecedented emphasis on capturing the complexities that arise in hydraulic fracturing to better design and execute hydraulic fracturing jobs. As the need for more sophisticated simulators grows, so does the need for more sophisticated physical models that can be used to study the mechanics of the fracturing process under a controlled environment, and to validate the numerical predictions of advanced hydraulic fracturing simulators. We developed and utilized novel laboratory capabilities to perform an extensive set of fracturing experiments across various aspects of hydraulic fracture propagation including the effect of far-field stress contrast, rock mechanical heterogeneity, multi-well injection, borehole notching, fluid injection method, type of injection fluid, and interaction with natural fractures. Numerous direct observations and digital image analyses are documented to provide fundamental insights in hydraulic fracturing. As demonstrated through a few case studies from the literature, our laboratory experiments are very useful for validating hydraulic fracturing simulators due to the small-scale, two-dimensional (2-D) nature, controlled environment, and well-characterized properties of the test specimens used in the experiments.
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (0.53)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (0.35)
- Data Science & Engineering Analytics > Information Management and Systems > Artificial intelligence (0.34)
Abstract Dynamic water, also known as smart water, injected at the end of conventional water flood by seawater, is known to show significant improvement in recovering additional oil. Different mechanisms have been proposed and lab measurements were conducted to understand the underlying process of additional oil recovery through dynamic water injection in lab conditions. In this work, we study the effects of different dynamic water injection scenarios on oil recovery in carbonate reservoirs based on reservoir simulations using representative fluid and rock properties with relative permeability curves obtained from core studies. To quantify the changes in measurable multiphysics properties due to dynamic water injection and reconcile multiphysics interpretation with additional oil recovery at field scale, a petrophysically consistent multiphysics effective property modeling is conducted. Based on the simulation results, dynamic water injection is shown to be effective in additional oil recovery at field scale post seawater injection. In addition, saturation changes caused by dynamic water injection result in detectable time-lapse contrast in the corresponding conductivity profiles, suggesting feasibility of the resistivity measurements to monitor dynamic water injection. This paper shows the advantages and benefits of petrophysically consistent multiphysics effective property modeling for a successful fluid monitoring design for quantifying the efficiency of dynamic water injection on additional oil recovery post seawater flood.
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (1.00)
- Energy > Oil & Gas > Upstream (1.00)
An Experimental and Simulation Study of CO2 Sequestration in an Underground Formations; Impact on Geomechanical and Petrophysical Properties
Fatima, Sobia (Dawood University of Engineering & Technology) | Khan, Hafiz Muhammad Mutahhar (Dawood University of Engineering & Technology) | Tariq, Zeeshan (King Fahad University of Petroleum & Minerals) | Abdalla, Mohammad (King Fahad University of Petroleum & Minerals) | Mahmoud, Mohamed (King Fahad University of Petroleum & Minerals)
Abstract Carbon dioxide (CO2) sequestration is a technique to store CO2 into an underground formation. CO2 can cause a severe reaction with the underground formation and injection tubing inside the well. Successful CO2 storage into underground formations depends on many factors such as efficient sealing, no escaping from the storage, and minimum corrosion to injection tubing/casing. Therefore, proper planning involving thorough study and reaction kinetics of CO2 with the underground formation is indeed necessary for proper planning. The main aim and objective of this study are to investigate the effect of CO2 storage with different cap rocks such as tight carbonate and shale under simulated reservoir conditions. The samples were stored for different times such as 10, 20, and 120 days. The objectives of the study were achieved by carrying out extensive laboratory experiments before and after sequestration. The laboratory experiments included were rock compressive and tensile strength tests, petrophysical tests, and rock mechanical tests. The laboratory results were later used to investigate the reaction kinetics study of CO2 with the underground formation using CMG simulation software. The effect of injection rate, the point of injection, purity of the injection fluid, reservoir heterogeneity, reservoir depth, and minimum miscibility pressure was analyzed. In this simulation model, CO2 is injected for 25 years using CMG-GEM simulation software and then the fate of CO2 post injection is modeled for the next 225 years. The simulation results showed a notable effect on the mechanical strength and petrophysical parameters of the rock after sequestration, also the solubility of CO2 decreases with the increase in salinity and injection pressure. The results also showed that the storage of CO2 increases the petrophysical properties of porosity and permeability of the formation rock when the storage period is more than 20 days because of calcite precipitation and CO2 dissolution. A storage period of fewer than 20 days does not show any significant effect on the porosity and permeability of carbonate reservoir rock. A sensitivity analysis was carried out which showed that the rate of CO2 sequestration is sensitive to the mineral-water reaction kinetic constants. The sensitivity of CO2 sequestration to the rate constants decreases in magnitude respectively for different clay minerals. The new simulation model considers the effect of reaction kinetics and geomechanical parameters. The new model is capable of predicting the compatibility of CO2 sequestration for a particular field for a particular time.
- Asia > Middle East (0.68)
- North America > United States (0.47)
- Europe > Denmark > North Sea (0.28)
- Europe > Norway > Norwegian Sea (0.24)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.49)
- Geology > Mineral > Silicate > Phyllosilicate (0.48)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.30)
- Geophysics > Borehole Geophysics (0.94)
- Geophysics > Seismic Surveying (0.69)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Tor Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Ekofisk Formation (0.99)
- Europe > Denmark > North Sea > Danish Sector > Central Graben > Block 5604/29 > South Arne Field (0.99)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Health, Safety, Environment & Sustainability > Environment > Climate change (1.00)
The Importance of Subsurface Characterization and Monitoring During Development and Operation of Underground Gas Storage Facilities
Guises, Romain (Baker Hughes Reservoir Technical Services, Reservoir Solutions) | Auger, Emmanuel (Baker Hughes Reservoir Technical Services, Reservoir Solutions) | Bordoloi, Sanjeev (Baker Hughes Oilfield Services, Business Transformation) | Ofi, Ayodele (Baker Hughes Reservoir Technical Services, Global Discipline) | Cranfield, Colin (Baker Hughes Reservoir Technical Services, Reservoir Solutions) | Freitag, Hans-Christian (Baker Hughes C3.ai, Intelligent Software Solutions)
Abstract Natural gas consumption is expected to grow significantly in coming decades in response to cleaner energy initiatives. Underground gas storage (UGS) will be key to addressing supply and demand dynamics for this transition to be successful. This technical paper will demonstrate the importance of an integrated subsurface characterization and monitoring approach not only for the construction of UGS, but also to guarantee safe and efficient operation over many decades. Key to long-term success of UGS is maximizing working capacity with respect to volume and pressure and maintaining well injection and withdrawal capabilities. Initial assessment steps involve determination of maximum storage capacity and an estimation of required cushion gas volumes. In similar manner to conventional field evaluation, we perform an integrated geological, geophysical, petrophysical and geomechanical characterization of the subsurface. However, for UGS facilities, the impact of cyclic variations of reservoir pressures on subsurface behavior and cap rock integrity also needs to be evaluated to determine safe operating limits at every point in time during the life of the UGS project. The holistic approach described above allows the operator to optimize the number of wells, well placement, completion design, etc. to ensure long-term safe and efficient operations. Furthermore, close integration of subsurface understanding with optimization of surface facilities, such as the compression system, is another critical component to ensure optimum UGS performance and deliverability. Moreover, another important task of the final phase of UGS facilities design involves enablement of sustainable operation through an asset integrity management plan. This phase is articulated around reservoir surveillance plans that monitor pressure, rock deformation and seismicity, in addition to regular wellbore inspection. Through close operations monitoring and the utilization of advanced data analytics, observations are compared to existing models for validation and operation optimization. Importantly we show that adapted monitoring programs provide critical long-term insight regarding the field response during successive cycles, leading to significant improvement in working gas capacity. A key consideration of this integrated UGS development strategy is based on the seamless integration of subsurface characterization, wellbore construction and well completions to ensure technical and commercial flexibility. The approach also emphasizes the integration with surface facilities design to ensure a true "Storage to Consumer" view for effective de-bottlenecking. Coupled with integrated subsurface integrity monitoring, this ensures a faster, cost efficient and safe response to the construction and operation of UGS facilities.
- Europe (0.94)
- Asia > Middle East (0.28)