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Results
Comparison of the Time-Lapse 4D Seismic Characteristics in MMV Between Carbonate and Clastic Reservoirs as CO2 Storage in Malay and Sarawak Basins, Malaysia
Tiwari, Pankaj Kumar (PETRONAS) | Das, Debasis Priyadarshan (PETRONAS) | Widyanita, Ana (PETRONAS) | Leite, Renato Jordan (PETRONAS) | Chidambaram, Prasanna (PETRONAS) | Patil, Parimal Arjun (PETRONAS) | Masoudi, Rahim (PETRONAS) | Tewari, Raj Deo (PETRONAS)
Abstract There are many gas fields associated with large amount of CO2 concentrations (>50 mol%) in offshore Malaysia. Development of the contaminated gas fields is only possible if a geologically safe storage site is identified for the storage of produced CO2. The critical component of CCS project field development plan is monitoring of the storage site for the long-term containment and conformance security. 4D time-lapse seismic is key in monitoring, measurement, and verification (MMV) plan. The time-lapse 4D seismic has been traditionally used to identify the potential threats associated with reservoirs with enhanced oil recovery plan. The application of 4D seismic would benefits CCS project for monitoring CO2 plume migration along existing or induced fractures. The study was conducted on identified CO2 storage sites in both depleted carbonate gas reservoir and clastic saline aquifer. It highlights two methods applied in the 4D AVO analysis, that quantifies the changes in CO2 saturation within reservoir during injection. The Aki and Richards’ approximation were analyzed for the effect of changes in gas saturations on the seismic amplitudes and the Smith and Gidlow's approximation for the reflection coefficient relationship between the AVO gradient/intercept attributes and reservoir fluid/properties. The application of 4D seismic would benefits CCS project for monitoring CO2 plume migration along existing or induced fractures. The study was conducted on identified CO2 storage sites in both depleted carbonate gas reservoir and clastic saline aquifer. It highlights two methods applied in the 4D AVO analysis, that quantifies the changes in CO2 saturation within reservoir during injection. The Aki and Richards’ approximation were analyzed for the effect of changes in gas saturations on the seismic amplitudes and the Smith and Gidlow's approximation for the reflection coefficient relationship between the AVO gradient/intercept attributes and reservoir fluid/properties. This study focuses on the different characteristics on 4D seismic attributes for carbonate and clastic reservoirs and discusses to effectively utilize for MMV.
- Asia > Malaysia > Sarawak > South China Sea (0.41)
- Asia > China > South China Sea (0.41)
- North America > United States > Texas (0.28)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Block 21/10 > Forties Field > Forties Formation (0.99)
- Europe > United Kingdom > Atlantic Margin > West of Shetland > Faroe-Shetland Basin > Judd Basin > Block 204/25 > Greater Schiehallion Field > Schiehallion Field (0.99)
- Europe > United Kingdom > Atlantic Margin > West of Shetland > Faroe-Shetland Basin > Judd Basin > Block 204/20 > Greater Schiehallion Field > Schiehallion Field (0.99)
- (10 more...)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > CO2 capture and sequestration (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Four-dimensional and four-component seismic (1.00)
- Health, Safety, Environment & Sustainability > Environment > Climate change (1.00)
- Facilities Design, Construction and Operation > Unconventional Production Facilities > CO2 capture and management (1.00)
Abstract Carbonate acidizing has been used for nearly a century in the oil and gas industry. Despite the numerous research efforts to understand the acid effect on carbonate reservoirs, the majority of the work only considered fully water saturated samples, which does not accurately duplicate the situations encountered in the field. The objective of this work is to investigate the effect of oil saturation on the acid volume requirements and the optimum injection rate. Coreflood experiments were used to examine the effect of the presence of oil on both the pore volume to breakthrough and the optimum injection rate. Three saturations were considered: fully water-saturated, residual oil saturated, and connate water saturated cores. Six different flow rates were tested: 1, 2, 3, 5, 10, and 15 cm/min. Cores were tested under both aged and unaged conditions to investigate the wettability effect. The pore volumes of acid injected to reach breakthrough were used to identify the optimum injection rate for each set of experiments. The wormhole shape was inspected using computed tomography. Experimental results show that the oil saturation improves the efficiency of limestone acidizing by decreasing the volume requirements to achieve breakthrough. The pore volume to breakthrough for all flow rates decreased from the fully saturated conditions, with the connate water saturation condition showing the lowest acid volume required. A correlation between the oil saturation, the pore volume to breakthrough for fully water saturated cores, and the pore volume to breakthrough for oil saturated cores is proposed. This correlation can predict the acid requirements for oil saturated conditions, in agreement with the current literature. Additionally, the oil saturation decreased the optimum injection flow rates due to the change in the area available to flow, and thus, the effective acid velocity in the pores. Lastly, the rock wettability effect was minimal on both the volume and the optimum injection rate. This work explains the contradicting observation in the literature and determines the effect of the initial oil saturation on the wormhole process. In addition, a new correlation is suggested that can help industry professionals better design acid field treatments to account for the effect of oil present in the near-wellbore area.
- Research Report > Experimental Study (1.00)
- Research Report > New Finding (0.90)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (0.93)
A Lab-to-Field Approach and Evaluation of Low-Salinity Waterflooding Process for High-Temperature High-Pressure Carbonate Reservoirs
Sarma, Hemanta Kumar (University of Calgary) | Singh, Navpreet (University of Calgary) | Belhaj, Ahmed Fatih (University of Calgary) | Jain, Adarsh Kumar (Institute of Reservoir Studies/Oil and Natural Gas Corporation Limited, now retired) | Gopal, Giridhar (Institute of Reservoir Studies/Oil and Natural Gas Corporation Limited) | Srivastava, Vivek Raj (Institute of Reservoir Studies/Oil and Natural Gas Corporation Limited)
Abstract Low-salinity waterflooding (LSWF) process has gained great attention over the years as a promising enhanced oil recovery (EOR) method with its superior performance over high-salinity water waterflooding. This study presents a rigorous and systematic lab-to-field approach involving research, discovery and validation using experimental and simulation components. Impact of various ionic compositions on LSWF was determined including a fundamental understanding of water geochemistry and likely geochemical reactions. The roles of crude oil/brine/rock (COBR) interactions and resulting rock-surface charges were investigated as well. Both experimental and simulation components were treated as complementary to each other. Experimental components included: reservoir-condition high-pressure high-temperature (HPHT) displacement tests in composite cores using brines of different salinities and specially-designed ionic compositions; investigation of wettability alteration - presumably a key LSWF mechanism - in a unique and specifically-designed HPHT imbibition cell; Zeta potentiometric studies were conducted using a Zeta potentiometer capable of more representative evaluation in brine-saturated whole cores rather than with pulverized samples. Simulation involved: proposing likely geochemical reactions during LSWF; incorporating oil/brine/rock interactions, and then, simulation studies linking laboratory data to data from the candidate reservoir on complementary basis. The findings of the coreflooding experiments proved conclusively that LSWF with certain specific ionic composition yield a higher oil recovery. HPHT imbibition tests yielded both visual and quantitative estimations and monitoring of how the wettability alteration took place during LSWF and how it was impacted by the degree and magnitude of both temperature and pressure as the vivid variations in the contact angles were clearly captured. Using a whole reservoir core rather than pulverized samples, Zeta potentiometric studies enabled an investigation of the charging behavior at the rock-water interface at various salinities. A new method to estimate Zeta potential in high-salinity environment was developed and validated, and it conclusively proved that rock-surface charge played a vital, if not a more dominant role, in the LSWF process. The simulation studies included incorporation of experimental data generated during the study, identification of a set of likely geochemical reactions during the process and complementary field data to study the LSWF performance under various conditions and constraints. A conceptual "lab-to-field" approach that can contribute to designing a more efficient LSWF process with optimized ionic chemistry has been proposed based on results and analysis from this study.
- Europe (1.00)
- Asia > Middle East (1.00)
- North America > United States (0.93)
- Asia > India (0.68)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Rock Type > Sedimentary Rock (0.69)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.67)
- Europe > United Kingdom > Atlantic Margin > West of Shetland > Faroe-Shetland Basin > Rona Ridge > Block 206/9 > Clair Field (0.99)
- Europe > United Kingdom > Atlantic Margin > West of Shetland > Faroe-Shetland Basin > Rona Ridge > Block 206/8 > Clair Field (0.99)
- Europe > United Kingdom > Atlantic Margin > West of Shetland > Faroe-Shetland Basin > Rona Ridge > Block 206/7 > Clair Field (0.99)
- (4 more...)
Abstract Wireless communication in subsurface wells and reservoir has been a major challenge in ensuring robust data transmission, and reliable communication between the sensors. Challenges from the multiple reflection as well as other external factors, makes subsurface communication a unique challenge for modern communication algorithms. While multiple-Input, multiple-output orthogonal frequency division multiplexing (MIMO-OFDM) communication has been extensively implemented in wireless communication for signal processing, unique challenges arise in subsurface reservoirs caused by unknown formation properties and fluid movements. We present a new smart MIMO-OFDM algorithm for wireless communication in subsurface reservoirs. The new algorithm integrates both MIMO and OFDM into a deep learning framework. It optimizes the communication quality as well as reliability of the communication between the various subsurface wireless devices. The joint integration and smart adjustment leverages the power of both algorithms simultaneously, and allows significantly improved communication robustness between the wireless devices. We tested the smart MIMO-OFDM on a synthetic carbonate reservoir formation with multiple wireless sensors and wireless appliances. Fracture Robots (FracBots, about 5 mm in size) technology will be used to sense key reservoir parameters (e.g., temperature, pressure, pH and other chemical parameters). The technology is comprised of a wireless microsensor network for mapping and monitoring fracture channels in conventional and unconventional reservoirs. The system establishes wireless network connectivity via magnetic induction (MI)-based communication, since it exhibits highly reliable and constant channel conditions with sufficiently communication range inside an oil reservoir environment. The results exhibited strong performance of the wireless communication, hence providing reliable and robust subsurface wireless communication. The novel framework presents a vital component in enhancing subsurface wireless communication and achieve robust data transfer. The results outline the opportunity for wireless communication to become a critical component for subsurface communication.
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (0.56)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (0.55)
- Data Science & Engineering Analytics > Information Management and Systems > Neural networks (0.55)
- Data Science & Engineering Analytics > Information Management and Systems > Artificial intelligence (0.48)
De-Risking and Optimisation During Gas Field Development Using Integrated Ultra-Deep Reservoir Mapping and Advanced Surveying Technology: A Case Study from Offshore Malaysia
Abu Talib, M. Ashraf (Petronas Carigali Sdn. Bhd.) | Zulkifli, M. Safwan (Petronas Carigali Sdn. Bhd.) | Annuar, M. Nasrullah (Petronas Carigali Sdn. Bhd.) | Ahmad Ani, M. Qayyum (Petronas Carigali Sdn. Bhd.) | Mondali, Mondali (Petronas Carigali Sdn. Bhd.) | Mohamed, Nooraini (Petronas Carigali Sdn. Bhd.) | Shields, Daren James (Petronas Carigali Sdn. Bhd.) | Djumeno, Rochmad Sutattyo (Petronas Carigali Sdn. Bhd.) | Yusoff, Faidhi (Petronas Carigali Sdn. Bhd.) | Ozoemena, Amaechi Emmanuel (Petronas Carigali Sdn. Bhd.) | Wan Muda, W Mohd Sharif (Petronas Carigali Sdn. Bhd.) | W Mohamad, W Amni (Petronas Carigali Sdn. Bhd.) | Hardiani, Rosidah (Petronas Carigali Sdn. Bhd.) | Rajan, Preveen Kumar (Petronas Carigali Sdn. Bhd.) | Mustafa, M Azlan (Petronas Carigali Sdn. Bhd.) | M Bukhari, Khairul Amri (Petronas Carigali Sdn. Bhd.) | Za’ba, Muhammad Afiq Zaim (Schlumberger) | Alang, Khairul Anuar (Schlumberger) | Thanh, Phung Nguyen (Schlumberger) | Wang, Haifeng (Schlumberger)
Abstract Recently, Petronas Carigali Sdn. Bhd. in Malaysia has successfully drilled two horizontal wells to boost the gas production of the brown field X, offshore Malaysia. The field X has been producing for many years and production started to decrease since early 2013, requiring immediate infill drilling to cover for the production gap. However, the well planning and execution are very challenging. Due to the target location, the Extended Reach Drilling (ERD) well trajectory design was considered. It would need high drilling efficiency to minimize the extended stationary time to reduce the stuck pipe and ensure the accuracy of landing and geo-steering the well. Moreover, the high uncertainty of subsurface data like gas water contact (GWC), the complexity of carbonate reservoir heterogeneities, reservoir rugose geomorphology caused by fractures or karst and the large variation of reservoir resistivity profile added more difficulties for the pre-drill modeling and real-time execution. The planning methodology combined between several planned trajectories and possible reservoir geological models to achieve the best fit of the current reservoir condition and the planned well objectives. Then, the well placement pre-drill modeling would be performed to optimize the geo-steering execution to maximize the reservoir exposure and place the well in the desired position inside the target layer. Eventually, drilling execution was smoothly and successfully performed. The first well was drilled 614m MD horizontally at approximately 21m TVD above the GWC, exceeding the target objective of 12m TVD standoff. The second well, which was the ERD well, drilled 349m MD horizontally, approximately 6.6m TVD below the top of carbonate. Utilizing the ultra-deep reservoir mapping to identify the top of carbonate, carbonate heterogeneity layers and GWC helped precisely optimize the well in the desired position. Combination of definitive dynamic survey (DDS) technology not only provided better trajectory TVD calculation for improving reservoir mapping boundaries, but also helped to speed up the drilling operation by reducing the standard surveying time, ultimately minimizing the risk exposure for stuck pipe. This paper will describe how the combination of well placement technology ultra-deep reservoir mapping tool and latest definitive dynamic surveying technology helped Petronas achieve the objectives and de-risk and optimize the horizontal wells from planning to operation.
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > Malaysia Government (0.45)
Leap of Faith from Conventional to EM Look-Ahead: A Game Changing Technology to Improve Well Efficiency
Mahardi, Muhamad Yanuar (PT Pertamina EP) | Hendarsyah, Hendarsyah (PT Pertamina EP) | Endarmoyo, Kharisma (PT Pertamina EP) | Soewargono, Dadang (PT Pertamina EP) | Naskawan, Arie (PT Pertamina EP) | Hakim, Arif Rachman (PT Pertamina EP) | Soekmono, Oktaviano (PT Pertamina EP) | Ardikani, Nadia (Schlumberger Oilfield Services) | Bauch, Thorsten (Schlumberger Oilfield Services) | Azwar, Olivia (Schlumberger Oilfield Services) | Permanasari, Dian (Schlumberger Oilfield Services) | Wilasari, Ni Made (Schlumberger Oilfield Services) | Supriatna, Erik Gunawan (Schlumberger Oilfield Services) | Pasaribu, Ihsan Taufik (Schlumberger Oilfield Services) | Vataneta, Rendiza (Schlumberger Oilfield Services) | Yamin, Muhammad Faizal (Schlumberger Oilfield Services)
Abstract The PEP structure in Matindok block in Central Sulawesi has been proven to produce gas reserves in the Minahaki formation based on the first exploration well PEP-001 that was drilled in 2018. The PEP structure has a Miocene carbonate build-up play, and the target reservoir is the M member pinnacle carbonate reef. One of the main challenges in this area is low resolution of seismic data, leading to a high depth uncertainty of top M position. The PEP-001 well was planned to set the 9 ⅝-in casing point above top M. Offset wells did not show any clear markers in the thick shale above M formation, that could have been used for log correlation. In previously drilled offset wells correlation was done conventionally by taking cutting samples and relying on drilling parameters break. However, when PEP-001 was drilled, no apparent drilling break was observed. By the time cuttings reached surface, the bit had drilled into 20-m thickness of M formation. Since casing covered most part of the upper carbonate formation, open hole logging and well testing data were not acquired to delineate target M formation optimally. The second exploration well PEP-002 was planned with an objective to set 9 ⅝-in casing ~5 m above top M to acquire a full interval coverage of coring, open hole wireline logging, and well testing program. This information was critical for optimal reservoir delineation to allow for accurate reserve calculation and future structure development. Conventional correlation (well-seismic pairing and correlation) has proven insufficient for casing point placement and was a lesson learned from PEP-001. The presence of limestone stringers observed in offset wells within proximity of top M presented an additional challenge. The stringers could have been mis-interpreted as the main carbonate body, if interpretation was solely based on cutting samples. Based on these challenges, a technology with the capability to map and detect lithology changes ahead of the bit in real time was required. Real-Time EM Look Ahead technology uses deep directional electromagnetic (EM) technique to detect formation feature ahead of the bit. A feasibility study was done to simulate the tool response and define the placement of transmitter and receivers (spacings) in the BHA, as well as frequency selection based on the resistivity properties from offset wells. Based on the simulation, this technology was expected to detect top M formation as early as 10 m ahead of the bit. While drilling, top M could be resolved at 6 m ahead of the bit with an uncertainty of <1 m, therefore making this the fit-for-purpose technology to place the 9 ⅝-in casing point ~5 m above the M formation. As a result, 9 ⅝-in casing was successfully placed 5 m above top M. High resistivity contrast, that is expected to be top M, was mapped continuously from 10 m ahead of the bit. The decision was to set the casing point at 1706 m MD, 4-5 m from the estimated top M. Coring results and open hole logging in the subsequent 8 ½-in hole section confirmed that top M was at 1711 m MD, 5 m from the casing point, which was precisely as estimated from Real-Time EM Look Ahead Technology. This technology also helped detect thin limestone stringer and differentiate it from the target carbonate formation. It prevented 9 ⅝-in casing to be set ~118 m shallower where the first limestone stringer was observed. This has avoided extra operating days in case of drilling problems due to long exposed shale in the subsequent 8 ½-in hole section. The potential cost savings were estimated at USD 1.35 million for an additional 6-in hole section. Following this success, the same technology will be used in the next planned exploration wells.
- North America > United States > Texas > Dawson County (0.24)
- Asia > Indonesia > Sulawesi (0.24)
- Asia > Indonesia > Central Sulawesi (0.24)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Limestone (0.67)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.46)
- Geology > Sedimentary Geology > Depositional Environment > Marine Environment > Reef Environment (0.45)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Seismic Interpretation (0.35)
- North America > United States > Oklahoma > Anadarko Basin > M Formation (0.99)
- Asia > Malaysia > Sulawesi > Central Sulawesi > Senoro-Toili JOB – PSC Area > Minahaki Formation (0.99)
- Asia > Indonesia > Sulawesi > Central Sulawesi > Matindok Field > Minahaki Field (0.89)
Investigation of the Failure Mechanism and Complicated Wellbore Instability Issues in the Drilling of the Extra Deep Fractured Carbonate Reservoirs in Shunbei Field, NW China
Chen, Xiuping (Sinopec Northwest Oilfield Branch Petroleum Engineering Technology Research Institute) | Li, Shuanggui (Sinopec Northwest Oilfield Branch Petroleum Engineering Technology Research Institute) | Wang, Shanshan (Baker Hughes) | Gui, Feng (Baker Hughes) | Zhou, Yongsheng (Baker Hughes) | White, Adrian (Baker Hughes)
Abstract The Ordovician fractured carbonate reservoir in the Shunbei field is buried ~7300m below ground level and has presented great challenges for the drilling of extra deep, deviated development wells. Borehole instability-related drilling problems including pipe stuck, pack-off, and mud losses have been experienced frequently during drilling, with many wells being sidetracked three or four times before reaching the target. To understand the failure mechanism and optimize the drilling design to mitigate the drilling risk has become crucial for the field development. As the basis of the investigation, detailed geomechanical modelling was conducted for a selected area with the most representative drilling problems. Laboratory core tests, wireline logs, image data and drilling experiences were used to build geomechanical models characterizing the in situ stress, pore pressure and rock mechanical properties in both the overburden and reservoir sections. Stress-induced borehole failures observed in the image logs were analysed to help diagnose the failure mechanisms together with the cavings recovered from the problematic wells, which provided significant insights into the likely nature of instability problems in the wells. The geomechanical modelling from a series of wells revealed that the stress magnitudes in the selected area vary based on the structural location. The wells near the major fault system appear to be in a normal faulting stress regime in the Ordovician reservoir, while the wells nearby the secondary fault system are in a strike-slip faulting stress regime. Different stress regimes and horizontal stress anisotropies have resulted in different behaviors during drilling, with breakouts seen in some vertical wells while not in other vertical wells despite using similar mud weights. during drilling. The variable stress conditions plus the highly developed fractures have caused serious borehole collapse in some wells, but reasonably good hole condition in other wells. Wells using higher mud weight are not necessarily the ones having fewer drilling problems. Although the complex lithology, great depth, and unpredictable distribution of intrusive rocks has complicated the drilling problems, a proper definition of suitable mud weight to control borehole collapse and understanding of the natural fractures might play a bigger role in maintaining borehole stability and mitigating drilling risk. A good understanding of the stress condition and rock mechanical properties appears to be helpful in defining the proper mud weights and optimizing other drilling parameters to help mitigate the complex drilling problems encountered during drilling in the Shunbei field. However, additional work on the fracture distribution and trend of stress change in the field might be required to help investigate the problem further.
Abstract Oil and gas companies operating carbonate oil and gas condensate fields in Kazakhstan have been carrying out acid stimulation activities leading to a substantial increase in hydrocarbon production. Nearly all treatments were considered a success. Nevertheless, a certain level of optimization in the production enhancement methods that could, potentially, have brought additional technical and financial benefits, were overlooked due to various reasons. A comprehensive review of historical treatments on several fields located in West-Kazakhstan region was performed to identify areas to improve post-stimulation well performance. This review identified improvements including "cleaner" fluid selection, optimised design and treatment schedules. Historical treatments in the oil field typically used straight hydrochloric acid as the main acid, polymer-gelled (self-diverting) acid as the chemical diverter, and linear guar gel for displacement, and diagnostic tests. The application of a modern single-phase retarded acid to replace the straight hydrochloric acid was identified as a key improvement that would yield more efficient wormhole generation and an improved stimulation ratio. Another opportunity for improvement was to upgrade the chemical diversion system from polymer-based self-diverting acid to a viscoelastic surfactant-based (polymer-free) diverting acid system. The use of an oil-based displacement fluid with high retained permeability instead of linear gel and to reduce the hydrostatic pressure post-acidizing, thereby improving flowback, was also employed. Extended core flow testing for regained permeability and solubility were carried out with several acid systems to compare their capabilities and efficiency to create conductive wormholes, and their dissolution capacities. Additionally, emulsion, and sludging tendency upon contact with wellbore tubulars and formation crude was checked to verify the acids’ compatibility with hydrocarbons produced from the target reservoir. After the prerequisite laboratory testing, field trials commenced applying various combinations of fluid technologies in high-rate matrix stimulation treatments. The optimizations resulted in higher (normalized) post-stimulation productivity index (PI), facilitated formation cleanup, and enabled more efficient operations. A similar approach is, currently, being implemented in other stimulation projects in the region, and the results are being replicated. As has been mentioned above, one of the main enhancements implemented as part of this work is the employment of the single-phase retarded acid. Most of the published literature discussing application of the acid covers the cases of stimulation of relatively hot reservoirs (BHST>100°C) as acidizing of high-temperature carbonate rock using traditional hydrochloric acid is a great challenge. The current paper provides details of the case studies, where the acid system was successfully implemented in combination with several other stimulation technologies for mid-temperature ranges. One of the objectives was also to assess whether application of reduced volumes of the retarded and diverting acids would still lead to improved wells’ productivity. Positive results of the laboratory studies, treatment modeling, and field trials were validated by the increasing normalized post-stimulation PI with each optimization step.
- Asia > Kazakhstan > West Kazakhstan Region (0.24)
- North America > United States > Louisiana (0.15)
- Asia > Kazakhstan > Mangystau Oblast > Precaspian Basin > Tengiz Field > Tengiz Formation (0.99)
- Asia > Kazakhstan > Mangystau Oblast > Precaspian Basin > Tengiz Field > Korolev Formation (0.99)
Nitrogen Gas Flooding for Naturally Fractured Carbonate Reservoir: Visualisation Experiment and Numerical Simulation
Song, Zhaojie (China University of Petroleum) | Hou, Jirui (China University of Petroleum) | Liu, Zhongchun (Sinopec Petroleum Exploration and Production Research Institute & Sinopec Key Laboratory of Marine Oil & Gas Reservoir Production) | Zhao, Fenglan (China University of Petroleum) | Huang, Shijun (China University of Petroleum) | Wang, Yong (China University of Petroleum) | Wu, Jieheng (China University of Petroleum) | Bai, Baojun (Missouri University of Science and Technology)
Abstract Tahe Naturally Fractured Carbonate Reservoir has implemented nitrogen gas flooding since 2013, with daily oil production of 7580 bbls and oil recovery increment of 0.83% by the end of 2015. However, the presence of fractures significantly affects gas swept volume and production performance, so large amount of oil reserves is poorly flooded due to gas channeling through fractures. The fluid flow mechanisms in fractured models were discussed in order to improve field gas flooding efficiency. Based on the geological constrains of Tahe Oilfield, fractured models with different apertures were fabricated using acrylic glass to model carbonate matrix wettability and for a better observation on fluid flow behavior. The models were placed vertically and horizontally to simulate the high-angle and low-angle fractures in the formation. Gas displacing oil experiments were performed at different injection velocities. The oil displacement characteristics were depicted and the production performance was recorded and discussed. Experimental data were history matched through numerical simulation, and thus a sensitivity study was conducted via design of experiments. For downward gas injection in the high-angle fractured model with a given aperture, a critical injection velocity was obtained below which piston-like displacement was observed. Channeling factor was defined to characterize the injected gas channeling features. It gradually increased and reached its maximum value with increasing injection velocities. The relationship between channeling factor and injection velocity was well fitted by Langmuir equation, and the mechanism behind it was elucidated. Based on their relationship, three gas/oil flow regions were illustrated including non-channeling, transitional channeling, and stable channeling. For all fractured models, the critical injection velocity increased and the maximum channeling factor declined with the increase of fracture aperture. A standard curve was plotted, which enables us to determine different flow regions according to the fracture aperture and injection velocity. For oil displacement in the low-angle fractured models, the top part was flooded at a specific range of injection velocity. Gravity effect was weakened and the middle part was flooded at relatively high injection velocities. Numerical fractured models were built and thus calibrated by history matching all the experimental data at different fracture apertures and injection velocities. A sensitivity study was conducted and the weighting of different variables was emphasized via DOE. Previous studies were mostly focused on gas flooding efficiency in naturally fractured carbonate reservoirs; however, this study visually depicted the gas-oil flow behavior through lab experiments, and demonstrated the weighting of different variables via numerical simulation using DOE. This paper could provide an insight into field gas injection projects and the development of the commercial numerical simulator that is specialized for naturally fractured carbonate reservoirs.
- North America > United States > Mississippi > Marion County (0.24)
- Asia > China > Xinjiang Uyghur Autonomous Region (0.24)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
Laboratory Study on Surfactant Induced Spontaneous Imbibition for Carbonate Reservoir
Qi, Ziyuan (Saudi Aramco) | Han, Ming (Saudi Aramco) | Fuseni, Alhasan (Saudi Aramco) | Alsofi, Abdulkareem (Saudi Aramco) | Zhang, Fan (RIPED of China National Oil Corporation) | Peng, Yuqiang (RIPED of China National Oil Corporation) | Cai, Hongyan (RIPED of China National Oil Corporation)
Abstract Chemical flooding has been successfully applied in sandstone reservoirs using surfactant-related formulations due to their abilities to reduce interfacial tension (IFT) between injection fluid and oil. This scheme need to be modified to fit the requirement of effective application in carbonate reservoirs that present preferably oil-wet or mixed wet. In this case, the wettability alteration should be triggered by a kind of surfactants that can change the wettability towards water-wet and induce the spontaneous imbibition of injection fluid into the carbonate matrix for higher oil recovery. In this study, 16 surfactant samples were screened aiming at an Arabian carbonate reservoir, among which 3 surfactant samples were selected for spontaneous imbibition experiments using Amott cells at 95°C. The experimental results presented the imbibition was induced by the surfactant solutions compared to effect of the brine. It also showed that brine imbibition recovery decreases with the increase of permeability and initial water saturation. Surfactant can effectively improve imbibition recovery, and cores with higher permeability show better increased imbibition recovery. Imbibition can be divided into three types based on the value of bond number, and recovery as well as recovery rate can also be correlated with bond number. The imbibition model is validated by two imbibition modes – surfactant imbibition and brine imbibition then surfactant imbibition – using UTCHEM simulator. This paper demonstrates the effect of surfactant induced spontaneous imbibition on oil recovery, which should be taken into account in the chemical flooding application for carbonate reservoirs.
- Asia (1.00)
- Europe (0.68)
- North America > United States > Texas (0.28)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.55)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.48)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)