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Results
Shallow-water carbonate structures are characterized by different shapes, sizes and identifying features, which depend, among other factors, on the age of deposition and on the carbonate factory associated with a specific geologic period. These variations have a significant impact on the imaging of these structures in reflection seismic data. This study aims at providing an overall, albeit incomplete, picture of how the seismic expression of shallow-water carbonate structures has evolved through deep time. 297 shallow-water carbonate systems of different ages, spanning from Precambrian to present, with a worldwide distribution of 159 sedimentary basins, have been studied. For each epoch, representative seismic examples of shallow-water carbonate structures were described through the assessment of a selection of discriminating seismic criteria, or parameters. The thinnest structures, commonly represented by ramp systems, usually occurred after mass extinction events, and are mainly recognizable in seismic data through prograding clinoform reflectors. The main diagnostic seismic features of most of the thickest structures, which were found to be Precambrian, Late Devonian, Middle-Late Triassic, Middle-Late Jurassic, some Early Cretaceous pre-salt systems, #8220;middle#8221; and Late Cretaceous, Middle-Late Miocene and Plio-Pleistocene, are steep slopes, and reefal facies. Slope-basinal, resedimented seismic facies, were mostly observed in thick, steep-slope platforms, and they are more common, except for megabreccias, in post-Triassic structures. Seismic-scale, early karst-related dissolution features were mostly observed in icehouse, platform deposits. Pinnacle structures and the thickest margin rims are concentrated in a few epochs, such as Middle-Late Silurian, Middle-Late Devonian, earliest Permian, Late Triassic, Late Jurassic, Late Paleocene, Middle-Upper Miocene, and Plio-Pleistocene, which are all characterized by high-efficiency reef builders.
- South America (1.00)
- North America > United States > Texas (1.00)
- North America > Canada (1.00)
- (5 more...)
- Phanerozoic > Paleozoic > Devonian (1.00)
- Phanerozoic > Mesozoic > Triassic (1.00)
- Phanerozoic > Mesozoic > Jurassic (1.00)
- (5 more...)
- Geology > Structural Geology > Tectonics (1.00)
- Geology > Sedimentary Geology > Depositional Environment > Marine Environment > Reef Environment (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (1.00)
- (3 more...)
- Geophysics > Seismic Surveying > Seismic Interpretation (1.00)
- Geophysics > Seismic Surveying > Seismic Processing (0.93)
- Geophysics > Seismic Surveying > Surface Seismic Acquisition (0.67)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling (0.45)
- Materials > Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.45)
- South America > Venezuela > Caribbean Sea > Gulf of Venezuela > Gulf of Venezuela Basin > Cardon IV Block > Perla Field (0.99)
- Oceania > Australia > Western Australia > Western Australia > Timor Sea > Browse Basin (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Timor Sea > Browse Basin (0.99)
- (82 more...)
Microfluidics for Carbonate Rock Improved Oil Recovery: Some Lessons from Fabrication, Operation, and Image Analysis
Duits, Michel H. G. (University of Twente, Physics of Complex Fluids Group (Corresponding author)) | Le-Anh, Duy (University of Twente, Physics of Complex Fluids Group) | Ayirala, Subhash C. (Exploration and Petroleum Engineering Center - Advanced Research Center (EXPEC ARC)) | Alotaibi, Mohammed B. (Exploration and Petroleum Engineering Center - Advanced Research Center (EXPEC ARC)) | Gardeniers, Han (University of Twente, Mesoscale Chemical Systems Group) | Yousef, Ali A. (Exploration and Petroleum Engineering Center - Advanced Research Center (EXPEC ARC)) | Mugele, Frieder (University of Twente, Physics of Complex Fluids Group)
Summary After the successful implementation of lab-on-a-chip technology in chemical and biomedical applications, the field of petroleum engineering is currently developing microfluidics as a platform to complement traditional coreflooding experiments. Potentially, microfluidics can offer a fast, efficient, low-footprint, and low-cost method to screen many variables such as injection brine composition, reservoir temperature, and aging history for their effect on crude oil (CRO) release, calcite dissolution, and CO2 storage at the pore scale. Generally, visualization of the fluid displacements is possible, offering valuable mechanistic information. Besides the well-known glass- and silicon-based chips, microfluidic devices mimicking carbonate rock reservoirs are currently being developed as well. In this paper, we discuss different fabrication approaches for carbonate micromodels and their associated applications. One approach in which a glass micromodel is partially functionalized with calcite nanoparticles is discussed in more detail. Both the published works from several research groups and new experimental data from the authors are used to highlight the current capabilities, limitations, and possible extensions of microfluidics for studying carbonate rock systems. The presented insights and reflections should be very helpful in guiding the future designs of microfluidics and subsequent research studies.
- North America > United States (1.00)
- Asia > Middle East (0.67)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.81)
- Geology > Mineral > Carbonate Mineral > Calcite (0.53)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- (4 more...)
Flow-Through Experiments of Reactive Ba-Sr-Mg Brines in Mons Chalk at North Sea Reservoir Temperature at Different Injection Rates
Andersen, Pรฅl รstebรธ (Department of Energy Resources, University of Stavanger (Corresponding author)) | Herlofsen, Sander Sunde (Department of Energy Resources, University of Stavanger) | Korsnes, Reidar Inge (Department of Energy and Petroleum Engineering, University of Stavanger) | Minde, Mona Wetrhus (Department of Mechanical and Structural Engineering and Materials Science, University of Stavanger)
Summary North Sea Chalk reservoirs in Norway are potential candidates for enhanced hydrocarbon recovery by modifying the injected brine composition. This work investigates how barium (Ba), strontium (Sr), and magnesium (Mg) brines interact when injected into chalk. Ba and Sr are often associated with mineral precipitation and occur in formation water, while Mg is present in seawater, commonly injected in chalk. Relatively clean (>99% calcite) outcrop chalk cores from Mons, Belgium, were flooded at 130ยฐC in triaxial cells with four brines containing 0.12 mol/L divalent cations, either 0.06 mol/L Sr and Ba, 0.06 mol/L Sr and Mg, or 0.12 mol/L Ba or Sr. Each brine was injected in a separate core, with 100โ150 pore volumes (PV). The injection rate varied between 0.5 and 8 PV/D. Produced brine was analyzed continuously and compared with the injected composition. After flooding, the cores flooded with only Ba or only Sr were cut into slices and analyzed locally in terms of scanning electron microscopy (SEM), matrix density, specific surface area (SSA), and X-ray diffraction (XRD). In all experiments, the produced divalent cation concentration was reduced compared with the injected value. The total reduction of injected cation concentration closely equaled the produced Ca concentration (from calcite dissolution). When flooding 0.12 mol/L Sr, the Sr concentration depleted 55%, while when flooding 0.12 mol/L Ba, 15% Ba depleted. When injecting equal concentrations of Ba and Sr, 40% Sr and 7% Ba depleted, while with equal concentrations of Mg and Sr injected, ~50% Sr was retained and almost no Mg depleted. Sr appeared to dominate and suppress other reactions. There was less sensitivity in steady-state concentrations with variation in injection rate. The similar modification of the brine regardless of residence time suggests the reactions reached equilibrium. Cutting the cores revealed a visually clear front a few centimeters from the inlet. The material past the front was indistinguishable from unflooded chalk in terms of density, SSA, microscale structure, porosity, and composition [XRD and SEM-energy-dispersive spectroscopy (EDS)]. The material near the inlet was clearly altered. Images, XRD, SEM-EDS, and geochemical simulations indicated that BaCO3 and SrCO3 formed during BaCl2 and SrCl2 flooding, respectively. Geochemical simulations also predicted an equal exchange of cations to occur. The matrix densities, porosities, and the distance traveled by the front corresponded with these minerals and suggested that the chalk was completely converted to these minerals behind the front. It was demonstrated that Ba, Sr, and Mg brines and their mixtures can be highly reactive in chalk without clogging the core, even after 100 + PV. This is because the precipitation of minerals bearing these ions is associated with simultaneous dissolution of calcite. The Ca-, Ba-, and Sr-mineral reactions are effectively in equilibrium. Previous investigations with MgCl2 (in pure and less pure chalk, at 130ยฐC) show injection rate-dependent results (Andersen et al. 2022) and smoother alterations [Mg precipitation was seen from inlet to outlet (Zimmerman et al. 2015)], indicating that Mg-mineral reactions at same conditions have a longer time scale. The limited distance mineral alteration has occurred, suggesting that adsorption processes, happening in parallel, can explain previous observations (Korsnes and Madland 2017) of Ba and Sr injection strengthening chalk. Flushing out formation water with these ions during injection may be a new water-weakening mechanism.
- North America > United States (1.00)
- Europe > Norway > North Sea (0.70)
- Europe > Denmark > North Sea (0.70)
- (2 more...)
- Geology > Geological Subdiscipline > Geochemistry (0.86)
- Geology > Geological Subdiscipline > Geomechanics (0.68)
- Geology > Mineral > Carbonate Mineral > Calcite (0.68)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Limestone (0.34)
- 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 > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/7 > Greater Ekofisk Field > Eldfisk Field > Tor Formation (0.98)
- (10 more...)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
A Novel Methodology to Improve Wellbore Integrity via Reliable Barriers: Integration of Remote Wireless Zonal Water Injection and Intelligent Water Control
Jin, Fu (CNPC Engineering Technology R&D Company Ltd.) | Longlian, Cui (CNPC Engineering Technology R&D Company Ltd.) | Bingshan, Liu (CNPC Engineering Technology R&D Company Ltd.) | Guobin, Zhang (CNPC Engineering Technology R&D Company Ltd.) | Chen, Chen (CNPC Engineering Technology R&D Company Ltd.)
Abstract More and more deep horizontal wells have been drilled over all the world, strata with much higher temperature are discovered, which increases the risk to wellbore integrity and has driven the evolution of zonal isolation methods. New methods aim to ensure that the completion equipment deployed by operating companies can guarantee the integrity of oil wells throughout their entire lifecycle. Several globally renowned oilfield service companies are actively developing mechanical, fluid activation, and chemical solutions to address the increasingly challenging downhole conditions. Meanwhile, the industry is increasingly recognizing the importance of employing precise water injection and water control technologies to enhance wellbore integrity of oil and gas producers. As oil and gas fields reach a certain stage of development, the heterogeneity between layers becomes more prominent, leading to interlayer conflicts. Due to significant variations in geological characteristics among strata, which affect the degree of water flooding control in practice, it is necessary to implement zonal water injection techniques. Wireless intelligent water distributors utilize pressure or flow fluctuations to transmit signals, enabling control of the opening of downhole water distributors to adjust injection rates. The digital data transmission eliminates the need for human intervention, greatly reducing operational costs and saving time and effort. Compared to conventional water distributors, these instruments demonstrate higher efficiency and accuracy in intelligent zonal water injection. They perform regular tests on the flow rates of each individual layer, allowing for a better understanding of water absorption conditions and pressure variations across the well. This achievement aligns with the goal of achieving sufficient and proper water injection for waterflooding development, thereby enhancing the effectiveness of water injection and facilitating precision waterflooding in oilfield operations. Meanwhile, the petroleum industry is increasingly recognizing the significance of water shutoff and production profile control in improving wellbore integrity in producers. Intelligent water control and profile control technologies, based on cutting-edge technologies such as big data and artificial intelligence, hold the potential for achieving closed-loop intelligent control of water shutoff and profile control processes. This advancement could significantly increase oil and gas well productivity and recovery rates, making it a research focus for prominent oilfield service companies in recent years. Key technologies in intelligent water shutoff and profile control include intelligent reservoirs, intelligent decision-making, intelligent water finding, intelligent plugging, intelligent construction, intelligent monitoring, intelligent testing, and intelligent evaluation. These technologies involve fields such as big data, artificial intelligence, quantum communication, supercomputing, the Internet of Things, smart devices, new materials, the Internet of Things, blockchain, 5G communication slicing, cloud computing, and virtual reality. Intelligent water injection and water control technologies have been applied in the Middle East region, with the most extensive application found in the NEB oilfield owned by ADNOC. These technologies have improved water injection efficiency in the NEB oilfield, achieving the goal of water shut off.
- Overview > Innovation (0.54)
- Research Report > New Finding (0.48)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Asia > Middle East > UAE > Abu Dhabi > Arabian Gulf > Rub' al Khali Basin > Bab Field > Thamama Group Formation (0.99)
- Asia > Middle East > UAE > Abu Dhabi > Arabian Gulf > Rub' al Khali Basin > Abu Dhabi Field (0.99)
- Asia > China > Shandong > North China Basin > Shengli Field (0.99)
- (3 more...)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Production and Well Operations (1.00)
Dual Ring Injection Fence Technology: A Novel Method to Optimally Co-Develop Hydrocarbon Reservoirs with Free Gas Caps Over Producing Oil Zones
Aikman, M. J. L. (Abu Dhabi National Oil Company, Upstream Development Technical Center Abu Dhabi, United Arab Emirates) | Mabrook, M. (Abu Dhabi National Oil Company, Upstream Development Technical Center Abu Dhabi, United Arab Emirates) | Jing, X. (Abu Dhabi National Oil Company, Upstream Development Technical Center Abu Dhabi, United Arab Emirates) | Al Hammadi, H. (Abu Dhabi National Oil Company, Upstream Development Technical Center Abu Dhabi, United Arab Emirates)
Abstract To develop oil fields with significant gas caps, some operators have utilized a water injection fence to be able to co-develop the gas cap and the oil leg. ADNOC is preparing to co-develop the gas cap and oil legs of many of its giant oil reservoirs by drilling horizontal water injection wells at the current gas oil contact, separating the gas cap from the oil leg. This allows co-production of both the gas cap and the oil leg. However, the use of a water injection fence can lead to a loss in hydrocarbon recovery (oil, gas and condensate) when water invades both the oil leg and the gas cap. Furthermore, injection of water into the gas oil contact zone could result in gas producers with high water production which could ultimately lead to the cessation of production from the gas production wells if the water in the production tubing cannot be lifted to surface. The Dual Ring Injection Fence Technology (DRIFT) provides a method to achieve high hydrocarbon recovery with much lower produced water handling. DRIFT also allows for the option to inject large volumes of CO2 into the reservoir to further improve gas, condensate and oil recovery and to sequester CO2 in the subsurface, leading to a very low CO2 footprint. Fundamental to DRIFT is a second set of horizontal inner ring gas injection fence wells (IRGIF wells) that offset the IRWIF wells. The IRGIF are placed in the lower flank of the gas cap, above the GOC contact. Gas production wells are drilled into the crest of the gas cap. Lean gas is injected into the IRGIF wells and gas is produced gas from the crestal horizontal gas production wells. To test and validate the method, a history matched numerical simulation model of a real giant oil field was used to explore the performance of DRIFT compared to the current field development plan which utilized only the IRWIF concept. Sensitivities were run comparing the placement of the injection rings relative to each other, both in terms of true vertical depth and lateral offsets. It was found that the Dual Ring Injection Fence Technology improves oil, gas and condensate recovery compared to the method of a single ring of water injection wells. By placing the second ring of gas injection wells down structure and producing from the crest, water short circuiting is greatly mitigated. However, it is noted that when water invades the gas cap, a substantial volume of gas is trapped in the water phase, since the residual gas saturation to water for this system is as high as 30%. If the gas is hydrocarbon, this represents a substantial value loss. To improve the recovery of hydrocarbon gas, the use of different sacrificial gases was examined. By injection of a gas with little economic value (such as CO2, N2, H2S or other), the sacrificial gas displaces the hydrocarbon gas before the invasion of water. When the water does invade, the gas that is trapped is of low economic value. Thus, there is a remarkable improvement in the net hydrocarbon gas recovered from the gas cap. Furthermore, if CO2 is the sacrificial injection gas, there is substantial environmental benefit as the greenhouse gas is injected into the reservoir for disposal and storage instead of being released into the atmosphere. In summary, DRIFT is a step change improvement over the current method of a single ring of water injection wells. Dual Ring Injection Fence Technology enables an increase in the recovery of oil, gas and condensate and a decrease in water short circuiting compared to a standard water injection fence method. This process leads to a lower carbon-intensity barrel, particularly when CO2 is used as the injectant in the inner ring of gas injectors.
- North America > Canada > Alberta (0.94)
- Asia > Middle East > UAE > Abu Dhabi Emirate (0.28)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > Middle East Government > UAE Government (0.34)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Deep Basin > Kaybob Beaverhill Lake Field > Kaybob South Field > Swan Hills Formation > 1976082 Kaybobs 10-12-62-20 Well (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Deep Basin > Kaybob Beaverhill Lake Field > Kaybob South Field > Duvernay Formation > 1976082 Kaybobs 10-12-62-20 Well (0.99)
- North America > Canada > Alberta > Turner Valley Field (0.99)
- (11 more...)
Reactive Transport Modelling for a More Rigorous Scaling Risk Evaluation and Mitigation in a Giant U.A.E Carbonate Field
Baraka-Lokmane, S. (TotalEnergies) | Wang, X. (Parex Solutions) | Bigno, Y. (ADNOC) | Decroux, B. (TotalEnergies) | Olsen, J. (TotalEnergies) | El Hassan, M. (ADNOC) | Younes, D. (ADNOC) | Singleton, M. (Heriot-Watt University) | Mackay, E. (Heriot-Watt University)
Abstract After years of peripheral water injection with no significant scaling issues, pattern water injection and water injection at the GOC (Inner Ring Water Injection, or IRWI) are planned to be implemented in various reservoirs of this giant field. In a few pilot pairs, seawater injection is already taking place at a smaller spacing than historically applied. This allows testing of the injection schemes and assessment of the effect of heterogeneities before deploying pattern water injection and IRWI in the longer term. In this context, the scaling risk at the producer has been evaluated. The scaling risk assessment carried out with a thermodynamic prediction model has shown both SrSO4 and CaSO4 risks due to the mixing of formation water with injected seawater. This modelling fails to take account of geochemical reactions occurring in the reservoir; consequently, the scaling risk is usually overestimated. In this work, a reactive transport reservoir modelling tool has been used to investigate the impact of injection water composition on the scaling risk at the producer. In this model, the following are incorporated: aqueous component transport, partitioning of CO2 between aqueous and hydrocarbon phases, aqueous speciation reactions, mineral precipitation/dissolution reactions and heat transport. The simulations have considered full and reduced sulfate seawater injection with and without the presence of a thief zone. When full seawater is injected, the producer faces a risk of CaSO4 and no risk of SrSO4. This is the consequence of various coupled in situ mineral reactions, including dissolution and precipitation of carbonates and sulfates, which depend on propagation of temperature and CO2 desaturation fronts, as well as the other aqueous components. With the presence of a thief zone, SrSO4 presents a small scaling risk soon after seawater breakthrough; CaSO4 deposition has an initial peak soon after SrSO4 scaling. When reduced sulfate seawater is injected with and without the presence of the thief zone, there is no scaling risk for either SrSO4 or CaSO4. The results obtained by the reactive transport modelling tool match the general trends of scale deposition observed in the pattern injection well pair pilot to date. In this pilot a thief zone was identified in the vicinity of the injector and has contributed to accelerated water breakthrough at the producer. A peak in SrSO4 scale was observed in the early phase of water production, in agreement with the modelling results. A geochemical transport reservoir model was able to provide a full picture of seawater breakthrough at the production well, considering the impact of the thief zone. The required level of sulfate in the injected seawater, to prevent sulfate scales at the producer, has been determined. These results will help determine the scale mitigation strategy for the future development of this field.
- Europe (0.68)
- Asia > Middle East > UAE > Sharjah Emirate (0.28)
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (0.16)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (1.00)
- Geology > Mineral > Sulfate (1.00)
- Europe > United Kingdom > North Sea > Central North Sea > South Viking Graben > Block 16/17 > Tiffany Field (0.99)
- Asia > Middle East > UAE > Sharjah > Oman Mountains Foldbelt Basin > Sajaa Field > Thamama Group Formation (0.99)
- Asia > Middle East > UAE > Abu Dhabi > Arabian Gulf > Rub' al Khali Basin > Ghasha Concession > Umm Shaif and Nasr Block > Umm Shaif and Nasr Field > Umm Shaif Field > Thamama Group Formation (0.99)
- (2 more...)
Leveraging Condition Based Major Overhaul for Higher Uptime and Profitability
Al-saedi, Khaled (ADNOC ONSHORE, ABU DHABI, UAE.) | Al Awadhi, Hesham (ADNOC ONSHORE, ABU DHABI, UAE.) | Kalhoro, Muhammad U Ddin (ADNOC ONSHORE, ABU DHABI, UAE.) | Nadeem, Muhammad (ADNOC ONSHORE, ABU DHABI, UAE.) | Al Harmi, Sultan (ADNOC ONSHORE, ABU DHABI, UAE.) | Al Halabi, Saleh (ADNOC ONSHORE, ABU DHABI, UAE.)
Abstract ADNOC's smart growth strategy necessitates all entities to maximize efficiency and profitability through transformation of business strategies and embracing the latest technologies. In oil and gas operations, major overhauling of rotating equipment is one of the main contributing factors to increasing operating cost and plant availability. However, to ensure the integrity and reliability of rotating equipment, a cost-effective maintenance strategy must be applied over the asset life cycle. In the pursuit of this objective, ADNOC Onshore Bu Hasa team worked towards optimization of major overhaul maintenance adapting a holistic approach for rotating equipment through transformation of maintenance overhauling strategy from traditional time based to condition-based overhaul. The condition-based maintenance overhaul strategy is based on accurate thermodynamic performance monitoring combined with physical condition assessment that was achieved through a customized digital solution. Condition-based overhaul strategy was applied mainly on three different types of equipment that includes large size process pumps (centrifugal), special type Helico-axial design Multiphase pumps and centrifugal gas compressors. As a first step, revised overhaul strategy applied on water injection pumps (high pressure multistage centrifugal pumps) considering its impact on recurring maintenance cost and scheduled down-time, as on average 6 to 8 units become due for major overhaul each year based on meter-based frequency. And gradually condition based overhaul strategy was extended to other large size process pumps such as multiphase pumps and centrifugal gas compressors. Through the transformation of maintenance major overhaul strategy for rotating equipments based on accurate condition assessment and evaluation, achieved a significant cost saving up to 30%, increased uptime by 15% extending overhaul interval based on accurate health assessment and utilizing specialist independent service providers with service base in the country and hence contributing to In-Country value (ICV) targets. The paper provides proven case study with examples of different types of rotating equipment where condition-based major overhaul was successfully deployed and adopting similar maintenance overhaul strategy for rotating equipment will help in achieving significant cost optimization over life cycle and maximize plant availability.
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.57)
- Government > Regional Government > Asia Government > Middle East Government > UAE Government (0.47)
Data Analytics Driven Subsurface Reservoir Sectorization Review of a Giant Abu Dhabi Onshore Field Carbonate Reservoir for Efficient Reservoir Management
Javid, Khalid (ADNOC Onshore) | Alshkeili, Sara (ADNOC Onshore) | Al-Hammadi, Fatema (ADNOC Onshore) | Benourkhou, Noureddine (ADNOC Onshore) | Al Sayari, Saleh Ali (ADNOC Onshore) | Kenawy, Maher (ADNOC Onshore) | Ryzhov, Sergey (ADNOC Upstream)
Abstract This paper discusses the approach used to sectorize mature giant carbonate reservoir located onshore Abu Dhabi for the purpose of reservoir management, offtake, and injection balancing. The reservoir is developed under line-drive WAG scheme in combination with peripheral water injection. Future development plan for the reservoir includes massive deployment of Maximum Reservoir Contact (MRC) horizontal wells and a gas-based EOR scheme. A practical data-driven approach, based on one of the ADNOC's Integrated Reservoir Management (IRM) workflows was selected for the purpose of sectorization. It starts from defining a number of possible sectorization schemes and goes through the review of: relevant geological data (faults and structural features, rock properties and facies distribution), well performance data (productivity/injectivity indices, WCT and GOR mapping, WOR/GOR vs. cum oil trends, well maturity indicators), reservoir performance indicators (fluid properties and reservoir pressure distribution, water, and gas front movement, streamline analysis and analysis of injection allocation factors). compliance to the future development plans. Through the review each of the preliminary sectorization schemes are scored for their compliance to IRM requirements and the scheme with the highest score is selected for the future implementation. Out of eight sectorization schemes proposed at the start, one single scheme compliant with most of the requirements of ADNOC IRM workflow was selected. This scheme honors major faults and lineaments, reflects observed variation in rock properties and pressure distribution and at the same time caters for the requirements of future development schemes. Selected sectorization scheme features five sectors, each having comparable number of wells, while number of wells "sharing" multiple sectors was reduced to the minimum. Being compliant to the distribution of reservoir pressure and to observed trends in well performance selected sectorization allows improved monitoring and management of voidage replacement, pressure maintenance and will cater for adequate surveillance planning and execution. Moving forward, selected sectorization scheme will be used for regular sector performance reviews aiming at identifying subsurface opportunities and areas of improvement and helping to drive efficient reservoir management decisions.
- Geology > Geological Subdiscipline (0.55)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.49)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > Middle East Government > UAE Government (0.56)
Abstract Tubular GRE lining technology has been globally applied used since 1960's in eliminating downhole tubular corrosion, replacing the elevated CAPEX of CRA OCTG and assuring steady oil, gas and water flow through the downhole string with its flow assurance benefits. Compared to conventional carbon steel whose failures are frequent, the GRE lined carbon steel provides long lasting protection which results in huge savings in life cycle cost. Likewise, compared to CRA material capable of withstanding corrosion issues, the GRE lined CS provides direct capital cost savings. Apart from the economic benefits, operators deploying GRE lined CS have enjoyed superior well integrity over the life cycle of the well. Abu Dhabi National Oil Company (ADNOC ONSHORE) implemented this technology in 2013 for the water disposal wells (5 wells as trial, all of them were successful). We will share the results of the caliper logs that have been run into these wells and the inspection of tubing pulled out of the disposal wells after 4 years in service. Following the assessment, which was satisfactory, the first Water Injection well with GRE lined tubing has been RIH in 2021, and plans for Oil producers with GRE lined tubing in Q2-2023. Till the time of writing this paper, 19 GRE lined strings have been RIH in Aon's water disposal wells, and 2 strings have been run in water injection wells (under study and field test and assessment). This paper shares the evolution of this technology within the Aon from the first installation to the development of a contract and how Aon geared to absorb this technology in their system. Some of the challenges that faced the company were: The modifications that were required to the wellsโ designs. How the service provider was aware of Aon's operational well intervention jobs. How this is compatible with the lining system.
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > Middle East Government > UAE Government (0.56)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Health, Safety, Environment & Sustainability > Environment > Water use, produced water discharge and disposal (1.00)
- (2 more...)
Modelling Approach of Optimum and Effective Well Length Evaluation for MRC Development Strategy.
Shbair, Alaa Fadel (Adnoc Onshore) | Kherroubi, Djamal (Adnoc Onshore) | Bosivert, Ian (Halliburton) | Noordin, Firdaus Bin Mohamed (Adnoc Onshore) | Melo, Raphael (Melo Energy) | Abdalaziz, Khalid Mohammed (Melo Energy)
Abstract Maximum Reservoir Contact (MRC) drains have been introduced and implemented as an attractive solution in reservoir developments to accelerate production/injection while optimizing the development costs. The main objective of this paper is to provide a workflow to assess the optimum well length (Lopt) and MRC wells evaluation. In addition, it aims to highlight the factors affecting actual Effective well length (Leff) based on a study performed on a giant oil field and the planned execution plans to mitigate wells with poor effective well length. A new approach is proposed to predict the optimum well length based on the proportionality of flux rates and productivity index (PI). The approach uses steady-state well modelling packages built using the static well data such as trajectories, reservoir/fluid properties, vertical and lower completion tuned with dynamic data such as surface well test data and downhole P& T measurements. Output results are oil influx rates along the trajectory, PI and production profiles. For the sensitivities, an automated well model base calculation was implemented through an Excel-Macro to facilitate performing different realizations of wellbore design, permeability ranges, and tubing sizes. Next, the evaluation of horizontal wells was assessed utilizing surveillance tools with the integration of the several factors affecting the effective well length. Prior to implementing MRC drilling, the asset team must assess the optimum well length (Lopt) for their reservoir settings where a certain limit for horizontal section indicates an increase in frictional losses and increment (Q, PI) is no longer favorable. Theoretical models indicate productivity and rates proportionality with horizontal length. While field case evidence of wells surveillance show effective length is rarely 100%. The findings proved the tool's efficiency to predict Lopt with the capability to reduce simulation runs/efforts for multiple scenarios. For the studied reservoirs, the Lopt was inferred to be in the range of 9000 up to 16,000 ft depending on the permeability, fluid properties, completion size and surface back pressure. Tubing diameter size was found to have a major influence on the flux rate, while wellbore diameter had a negligible impact. The workflow assessment on field studies with average conventional wells and MRC wells length of 1800 ft-10,000 ft inferred significant factors affecting actual well effective length to be: Well placement (Porous/dense), Heel-toe effects, Damage while drilling, production/Injection rate, Barefoot vs. completion, acid Stimulation after drilling, Well accessibility due to hole condition and production rate limits (Spinner threshold). The tool will help in the preliminary assessment to decide the optimum well length for the MRC, considering the reservoir settings and multiple completion options. In addition, the application can be extended to integrate with dynamic simulation as a robust tool to optimize completion design to be fit for future conditions. Furthermore, the field case set a generic workflow for confirming factors that may impact the Leff and evaluate MRC performance.
- Asia > Middle East > UAE > Abu Dhabi > Rub' al Khali Basin > Bu Hasa Field > Thamama Group > Shuaiba Formation (0.98)
- Asia > Middle East > UAE > Abu Dhabi > Arabian Gulf > Rub' al Khali Basin > Abu Dhabi Field (0.97)