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Collaborating Authors
Tight gas
- Information Technology > Knowledge Management (0.40)
- Information Technology > Communications > Collaboration (0.40)
Saudi Aramco announced today that it has begun producing first gas at the South Ghawar unconventional development. The world's largest oil company said the gas production from a tight sandstone formation was achieved 2 months ahead of schedule and is part of its broad initiative to boost Saudi gas output by more than half of 2021 levels by 2030. "This first production of unconventional tight gas from South Ghawar is a milestone that demonstrates real progress on our gas expansion strategy, which we believe has a role to play in meeting the Kingdom's needs for lower-emission energy and supporting growth in the chemicals sector," Nasir Al-Naimi, upstream president for Aramco, said in a statement. The company added that due to increasing domestic demand it will increase the facility capacity at South Ghawar from 300 to 750 MMscf/D. The facility can also process 38,000 B/D of condensate at current capacity.
- Government > Regional Government > Asia Government > Middle East Government > Saudi Arabia Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Texas > Permian Basin > Midland Basin > Kingdom Field > Abo Reef Formation (0.97)
- North America > United States > Texas > Permian Basin > Midland Basin > Kingdom Field > Abo Formation (0.97)
- Management > Energy Economics > Unconventional resource economics (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Tight gas (0.83)
Abstract Within the Queensland energy industry, unconventional gas, such as Coal Seam Gas (CSG) production holds significant importance. This study employs the Continuous Wavelet Transform (CWT) to analyze variations in CSG production, aiming to comprehend its complex production dynamics. The primary objectives of this research are to identify and categorize gas rate production variations, quantify their attributesโsuch as frequencies, durations, and magnitudesโand explore their integration into forecasting models. The study's results demonstrate successful identification and categorization of significant variations, specifically categorizing two types of variations impulse and step events. Through the CWT, the attributes of these events are quantified. Moreover, the obtained attributes are used to refine production forecasting via applying recreated production variations to conventionally smooth forecasting models such as type curves or history matching. The broader impact of the study lies in its ability to provide deeper insights into CSG reservoir behavior. By uncovering patterns often obscured by traditional analysis methods, the CWT approach allows for better understanding of the operational dynamics. Quantifying the production variation into meaningful metrics results in more accurate and reliable production forecasts and more informed decision-making in optimizing production strategies.
Mineralogical Based Geomechanical Model Assisted Hydraulic Fracture Design for Fiber Optics Well: Tested in a Tight Gas Sandstone Reservoir
Aamri, M. (Petroleum Development Oman) | Zadjali, R. (Petroleum Development Oman) | Sarfare, M. (Petroleum Development Oman) | Aamri, A. (Petroleum Development Oman) | Yaroubi, A. (Petroleum Development Oman) | Balushi, A. (Petroleum Development Oman) | Hattali, A. (Petroleum Development Oman) | Badi, S. (Petroleum Development Oman)
Abstract Accelerated gas production within PDO is crucial to meet the growing demand for natural gas. However, this requires effectively extracting gas from complex tight sandstone formations, which poses challenges and necessitates a deep understanding of formation behavior. Hydraulic fracturing has emerged as a key method for reservoir development in PDO. Some tight gas fields in PDO have been developed using vertical wells targeting two different hydrocarbon commingled sandstone units (A, B). To ensure successful hydraulic fracture design, a robust geomechanics model is essential. However, the current challenge lies in the limited ability to characterize mechanical properties across the formation using only sonic log data, which affects stress calculations and hampers the understanding of different mechanical barriers that impede fracture growth. Also, the stress and geomechanical properties of the reservoir are crucial factors influencing fracture design. This paper aims to discuss the application of a mineralogical-based geomechanical model to optimize hydraulic fracturing design and operations in tight gas sandstone reservoirs. A detailed mineralogical analysis of the reservoir rocks was conducted using a standard and existing workflow to identify the mineral composition. Additionally, data analysis was performed by correlating radioactive post-frac tracer results with the resulting minerals (e.g., TH and U). Multi-regression and machine learning algorithms were subsequently employed to predict mineral volume for all the wells studied. Consequently, three mineralogical qualitative curves were generated, providing insights into the dominant expected mineralogy. The paper proposes a new workflow to improve the geomechanical model by incorporating mineralogy and clay content. By adjusting elastic properties based on clay content, the stress model was calibrated using post-frac data. The effectiveness of this proposed method was tested and validated using Fiber Optics and post-frac radioactive tracer results. The results indicate the prevalence of quartz as the main mineral, with an increasing amount of K-feldspar observed in the lower reservoir section based on the Spectral Gamma Ray log. Additionally, the presence of various clay minerals significantly alters the elastic behavior of the reservoir rocks. The study presents low, expected, and high dominant mineral logs, utilizing a combination of multi-regression and Random Forest algorithms to account for the different subsurface characteristics of each reservoir. Notably, a strong correlation was found between the frac barrier and specific uranium and thorium concentrations. The application of this correlation to other wells demonstrated good agreement between the frac barrier determined by radioactive tracer data and the mineral composition of the rocks in the field. Furthermore, the study explores the update of the existing geomechanical model workflow based on the resulting mineral composition. This valuable information provides insights into the mechanical behavior of the rocks, as different minerals exhibit varying mechanical properties and responses to fracturing.
- Asia > Middle East > Oman (0.31)
- North America > United States > Texas (0.28)
- Asia > Middle East > Saudi Arabia (0.28)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Asia > Middle East > Oman > Al Wusta Governorate > Arabian Basin > Rub' al-Khali Basin > Barik Field > Barik Formation (0.97)
- Asia > Middle East > Oman > Miqrat Formation (0.96)
- North America > United States > Kansas > Rock Field (0.93)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Tight gas (1.00)
- (3 more...)
Fluid Identification with Multiple Nonelectrical Methods in Ultradeep Tight Gas Reservoir, A Case Study from Tarim Basin
Hu, Jianfeng (PetroChina Tarim Oilfield Company) | Zhao, Yuanliang (PetroChina Tarim Oilfield Company) | Shuai, Shichen (PetroChina Tarim Oilfield Company) | Ge, Shengquan (PetroChina Tarim Oilfield Company) | Cai, Liang (SLB) | Wang, Wei (SLB) | Wu, Jinlong (SLB) | Zhao, Xianran (SLB)
Abstract The complex geology of fold-and-thrust belt led to significant difficulties with the engineering aspects of drilling, logging, completion, and testing. The Bashijiqike Formation and Baxigai Formation feature a tight sandstone reservoir that exists below a salt layer with high pressure and high downhole temperature. Reservoir characterization is indispensable in the development of this Cretaceous structural fractured tight sandstone reservoir formation. Fluid identification is a key tool used to locate the sweet spot with high producibility for further development. Resistivity is the most common and straight-forward method. However, because of the mixed effect from pore structure, formation sedimentary dips, far-end fractures, and the influence of the surrounding rocks etc., gas and water cannot easily be identified based on the resistivity difference. Compressional coefficient and Poisson's ratio is without obvious cross-over effect because of the compaction effect on rock sonic waves. Under these circumstances, new methods based on other nonelectrical technologies are used. Nonelectrical means for fluid identification including T1โT2 based on 2D NMR measurement, and the spectroscopy related sigma and chlorine element method were successfully applied in this region. The 2D NMR measurements provide porosity and permeability information for T2 based analysis. When used in conjunction with T1 based measurement, the fluid identification through different T1โT2 response provides an advantage for distinguishing hydrocarbon and water, especially for gas. Since relaxation due to diffusion only applies to T2 and never to T1, given the typical magnetic field gradients of the logging tool, the oil and gas signal can easily be distinguished from the T1/T2 ratio. The continuous measurement enables the separation and quantitation of different fluids that exist in the pore system for the entire interval of the targeted reservoir. Formation water salinity is contributed by the NACL present in the fluid in this area. Advanced spectroscopy data provides chlorine measurements minus this effect in a mud system. The chlorine from the formation is calculated in this way. Formation water can be derived to further identify the main contributor of the fluid inside the pore system. Case studies are presented from this ultradeep tight gas reservoir that solved the fluid identification issue when resistivity cannot directly distinguish fluid type. The result matched the well with the test, which provided a novel solution to finalize the sweet spot interval for the targeted reservoir.
- North America > United States (0.69)
- Asia > China > Xinjiang Uyghur Autonomous Region (0.41)
- Europe > Norway > Norwegian Sea (0.25)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Structural Geology > Tectonics > Compressional Tectonics > Fold and Thrust Belt (0.74)
- Asia > China > Xinjiang Uyghur Autonomous Region > Tarim Basin (0.99)
- North America > United States > Louisiana > China Field (0.95)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Tight gas (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
A New analytical Model for Production Data Analysis in Horizontal Wells of Tight Gas Reservoirs
Li, Zhe (Oil & Gas Technology Research Institute, PetroChina Changqing Oilfield Company) | Hu, Lianbo (China University of Petroleum at Beijing) | Xie, Yonggang (Oil & Gas Technology Research Institute, PetroChina Changqing Oilfield Company) | Zhou, Changjing (Oil & Gas Technology Research Institute, PetroChina Changqing Oilfield Company) | Ma, Zhanguo (Oil & Gas Technology Research Institute, PetroChina Changqing Oilfield Company) | Liu, Jiaxin (Oil & Gas Technology Research Institute, PetroChina Changqing Oilfield Company) | Sun, Zhankun (Oil & Gas Technology Research Institute, PetroChina Changqing Oilfield Company) | Li, Gexuan (China University of Petroleum at Beijing) | Dong, Peng (China University of Petroleum at Beijing)
Abstract The evaluation of estimated ultimate recovery (EUR) in tight gas reservoirs holds paramount significance within the domain of unconventional oil and gas development. However, the accuracy of EUR prediction using traditional decline models is hampered by the complexity of the percolation environment after the compaction of tight sandstone and the limitations of commonly employed models. This paper proposes a new and rapid EUR evaluation method for tight gas reservoirs based on production data analysis (PDA). First, an improved model is utilized to fit the production dynamic history, enabling the determination of reservoir and fracture parameters. The introduction of the rate-normalized pressure (RNP) technique reduces the occurrence of multiple solutions during parameter inversion, simplifies the calculation of the linear flow parameter [(LFP= total fracture area ร square root of permeability)], and facilitates the estimation of EUR through productivity simulation. Secondly, to validate the reliability of the proposed method, an application analysis is conducted using the Sulige gas field as a case study. The results demonstrate that the LFP and EUR of the JA well are 1196.09 mยทmd and 3.17ร10 m, respectively. Furthermore, the EUR range of four representative wells is examined, revealing an actual range of 1.98ร10 m to 4.77ร10 m, while the EUR range obtained through linear analysis is 2.00ร10 m to 5.07ร10 m, with relative errors of 1.10%, 3.50%, 6.30%, and 1.05%, respectively. The average error remains within 5%. Additionally, correlation analysis conducted with over ten typical wells confirms a positive correlation LFP with EUR. In conclusion, this paper presents a novel and efficient methodology approach for predicting production and estimating ultimate recoveries in shale gas wells. By overcoming the limitations of traditional decline models, the proposed method offers improved accuracy and reliability in EUR evaluation. These findings enhance our understanding of EUR estimation in tight gas reservoirs and contribute to informed decision-making in the development of these valuable energy resources.
- Research Report > New Finding (0.89)
- Research Report > Experimental Study (0.66)
- Geology > Geological Subdiscipline (0.46)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.35)
- Asia > China > Xinjiang Uyghur Autonomous Region > Junggar Basin (0.99)
- Asia > China > Sichuan > Sichuan Basin (0.99)
- Asia > China > Shanxi > Ordos Basin > Changqing Field (0.99)
- (8 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Tight gas (1.00)
- Reservoir Description and Dynamics > Reserves Evaluation (1.00)
Abstract The primary goal of this study is to determine the irreducible water saturation in all types of reservoirs and highlight its significance in estimating hydrocarbon initial-in-place. Irreducible water saturation is strongly correlated to permeability and porosity, and it has a significant impact on reservoir characteristics. The irreducible water saturation refers to the quantity of water that is removable from the reservoir and occupies the reduced part of available effective porosity. It acts as a barrier preventing hydrocarbon accumulation. Accurately determining the irreducible water saturation is crucial for consistent and accurate interpretation of well log data, which, in turn, affects the estimation of oil and gas reservoir resources. In conventional petrophysics, resistivity logs are commonly used to identify pay zones based on the resistivity contrast between hydrocarbons and formation water. However, when a pay zone exhibits saturation-dependent Archie exponents or contains conductive minerals, these logs become inadequate for identifying producing zones and providing insights into water mobility. Consequently, many potentially productive zones with high irreducible water saturations are often overlooked in various fields around the world. Laboratory measurements offer accurate data on mobile water and irreducible water saturation, which includes bound water from clay and capillary. In this study, well log data results were utilized to calculate the irreducible water saturation in the reservoir. The analysis focused on the reliance of irreducible water saturation on the detailed pore structure. It was observed that irreducible water saturation decreases with increasing porosity and permeability. Additionally, factors such as pore and throat size, as well as the volume of clay or silt, impact the volume of irreducible water content. In tight gas reservoirs, the microscopic pore arrangement is more complicated, resulting in a higher proportion of micro-pores bound to water. Evaluating the reservoir requires attention to various factors that affects the saturation of irreducible water. Overall, this paper emphasizes the importance of accurately determining the irreducible water saturation in reservoirs and highlights the need to consider multiple factors when evaluating reservoirs to avoid overlooking potentially productive zones with high irreducible water saturations.
- Asia > Malaysia (0.28)
- Asia > Middle East (0.28)
- Geology > Mineral (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.48)
Successful Application of Solvent to Treat Condensate Banking in High Pressure, High Temperature Deep Tight Gas Reservoirs
Al Hinai, Adnan S. (Petroleum Development Oman, Muscat, Muscat, Oman) | Al Amri, Ghusun A. (Petroleum Development Oman, Muscat, Muscat, Oman) | Al Subhi, Salim K. (Petroleum Development Oman, Muscat, Muscat, Oman) | Al Kharusi, Dawood N. (Petroleum Development Oman, Muscat, Muscat, Oman) | Al Yaarabi, Ahmed M. (Petroleum Development Oman, Muscat, Muscat, Oman)
Abstract Condensate banking is a common challenge in tight gas reservoirs as it reduces the gas production rates. Solvent treatment is a temporary solution, it revives the well, but condensate will keep accumulating until the well quits again. The paper aims at presenting the best stimulation practices for condensate banking, examples from two high condensate gas ratio fields in the Sultanate of Oman. With the intentions of how solvent technology increased efficiency post-completion clean out and how shut-in wells were revived to produce more than 50m3/d of condensate with good sustainability. The paper summarizes the status of the field prior to implementing solvent treatment & the main challenges in the field, from the well intervention & production perspective. It also illustrates the technical selection & success criteria utilized to achieve the objectives. In addition, a brief explanation on the lab testing that was conducted prior to injecting the solvent into the well. It was observed that the crestal and western-flank wells are mainly affected by condensate banking (CB) and the impact varies depending on the petrophysical properties of the wells. While the eastern flank has scaling issues and suspected crossflow. Tight sandstones reservoirs were deemed not suitable unless the initial stimulation technique was hydraulic proppant fracturing. The target was to achieve a productivity index improvement between 1.5-2 times for condensate blocked wells and a minimum sustainability of 6 months. Laboratory trials were prepared on core samples from five different wells with three experimental approaches. One of the experiments showed inconclusive results. Condensate Emulsions were discovered for the first time. As an extra gain from the solvent system, was the possibility to degrade such emulsion at bottom hole conditions but further testing required to understand the technical reason. A well that was closed for almost twelve months initially produced condensate three times the expected rate for four months and had dropped by half and has been sustainable. Depending on the well condition, bull-heading the solvent can yield the same results as that of coil tubing, saving a good amount of cash. In-house customized solvent recipe showed a 66% reduction in cost per well. The paper will add information in the current reservoir stimulation techniques buy providing the lessons learnt to sustain gas production from challenging environments such as Sultanate of Oman's Fakhar tight gas field. Modelling condensate banking phenomenon in a dynamic reservoir model will improve our understanding of the challenge, and how we tackle it.
- Asia > Middle East > Oman (1.00)
- Asia > Middle East > Israel > Southern District (0.24)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- South America > Colombia > Casanare Department > Llanos Basin > Cupiagua Field (0.99)
- South America > Brazil > Parnaiba Basin > Block PN-T-68 > California Field (0.99)
- North America > United States > Mississippi > Pond Field (0.99)
- (5 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Tight gas (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Gas-condensate reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- (2 more...)
Tight Gas Reservoir Characterization and Comparison of PLT Methods: Micro-Seismic Monitoring, Fiber Optical Production Logging and Tracer Coated Sand Monitoring Applied in the Same Well
Yao, Xiao (Tight Oil and Gas Exploration and Development Project Department of Southwest Oil and Gas Field Company, Petrochina) | Qinggao, Zeng (Tight Oil and Gas Exploration and Development Project Department of Southwest Oil and Gas Field Company, Petrochina) | Haibo, Deng (Tight Oil and Gas Exploration and Development Project Department of Southwest Oil and Gas Field Company, Petrochina) | Linke, Song (Tight Oil and Gas Exploration and Development Project Department of Southwest Oil and Gas Field Company, Petrochina) | Xinggang, Liu (Tight Oil and Gas Exploration and Development Project Department of Southwest Oil and Gas Field Company, Petrochina) | Haiyan, Heng (Sichuan Hongrui Energy Technology Co., Ltd.) | Wenjing, Zhang (Sichuan Hongrui Energy Technology Co., Ltd.) | Geng, Sun (Beijing Geosplit Oil & Gas Field Technology LLC) | Guangyu, Wang (Beijing Geosplit Oil & Gas Field Technology LLC) | Belova, Anna (Beijing Geosplit Oil & Gas Field Technology LLC) | Husein, Nadir (GEOSPLIT MIDDLE EAST FZE)
Abstract Unconventional tight gas reservoir characterization is a complex process in continuous attempt to optimize hydrocarbon recovery. The production logging tools and formation evaluation tools currently existing in the market gained widespread adoption in conventional plays. Unconventional reservoirs are characterized with complex lithology, high heterogeneity and anisotropy. Typically, such reservoirs are developed by drilling clustered horizontal wells deploying multistage frac strategy to increase reservoir drainage and simulated reservoir volume (SRV). Accurate reservoir characterization is key to reduce uncertainties and economic feasibility of field developments. Operators are continuously looking to define reliable production logging tools for unconventional plays. This paper evaluates the comparison of three different measurement methods in the horizontal well straight after performing 15-stage hydraulic fracturing. The measurement methods in subject are: micro-seismic monitoring of neighboring wells, coiled tubing conveyed distributed acoustic sensing (DAS) and novel quantum based inflow tracers. Inflow tracer technology is fairly new solution and as such, will be elaborated in greater detail compared to the other two solutions.
- Geology > Petroleum Play Type (0.54)
- Geology > Rock Type (0.35)
Unlocking Hydrocarbon Potential in Tight Gas Reservoir in Onshore Abu Dhabi Through Different Completion Technologies
Bernadi, B. (ADNOC Onshore, Abu Dhabi, United Arab Emirates) | Al Ameri, S. S. (ADNOC Onshore, Abu Dhabi, United Arab Emirates) | Al Awadhi, F. O. (ADNOC Onshore, Abu Dhabi, United Arab Emirates) | Al Shehhi, H. A. (ADNOC Onshore, Abu Dhabi, United Arab Emirates) | Al Hosani, M. A. (ADNOC Onshore, Abu Dhabi, United Arab Emirates) | Al Bairaq, A. M. (ADNOC Onshore, Abu Dhabi, United Arab Emirates)
Abstract This paper will discuss some case studies on how to unlock the tight gas reservoirs potential in onshore field of Abu Dhabi through different drilling/completion strategies. Various technologies are tested i.e., Underbalanced Coiled Tubing Drilling (UBCTD), Smart Liner (LEL), Hydraulic Fracking (HF) and Fishbones (FB). The well performances after technology application are then evaluated to see any benefit from completion technology deployments to increase the production. The selection of wells for technology implementation was carried out; 3 wells for Hydraulic Fracking, 1 well for LEL, 1 well for UBCTD and 1 well for FB. The technology implementation was preferentially applied on new wells because it gives better customization to design and implement completion technology tailored to the specific reservoir conditions and production requirements. In addition, retrofitting the existing wells with advanced completion can be more challenging and costly, making it more impractical although in certain case it can be justifiable. Observation reveals that the laterals placement on the right hydrocarbon sweetspots are the utmost important key element of the successful well production. The application of drilling technique/new advanced well completion technologies will increase the chance of production success. Thorough evaluation was performed to learn what extent the application of the techniques can improve the production. The finding reveals that the success story is as the result of combination of good lateral placement technique in the potential sweetspots and the type of the technology selected. So far pilot well with UBCTD technology has been found to have the most remarkable success among other pilot wells. Investigations were also performed to find-out what can be wrong with the failed wells with the technology deployment. The analytical study also reveals that the advanced well completion technology in a new single horizontal well can outperform the performance of a conventional multilateral well and even it can double the production of a single open-hole lateral well with non-technologies implementation at this time.