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Results
Well Integrity Leak Diagnostic Using Fiber-Optic Distributed Temperature Sensing and Production Logging
Abeling, Joerg (Wintershalldea) | Bartels, Ulrich (Wintershalldea) | Singh, Kamaljeet (Schlumberger) | Dutta, Shaktim (Schlumberger) | Agrawal, Gaurav (Schlumberger) | Kumar, Apoorva (Schlumberger)
Abstract Fiber optics has many applications in the oil and gas industry. In recent years, fiber optics has found usefulness in leak detection. The leaks can be efficiently identified using fiber-optic distributed temperature sensing measurement, thereby mitigating the health, safety, and environmental (HSE) risk associated with well integrity. Further, a production log can be used to gain more insight and finalize a way ahead to resolve well integrity issues. An innovative solution-driven approach was defined, with fiber-optic distributed measurement playing a key role. Multiple leaks were suspected in the well completion, and a fiber-optic cable was run to identify possible areas of the leak path. After the fiber-optic data acquisition, a production log was recorded across selective depths to provide an insight on leak paths. After identifying leak depths, a definitive decision between tubular patching and production system overhaul was decided based on combined outputs of the fiber-optic acquisition and production log. Results are presented for a well where multiple leaks were successfully identified using the novel operational approach. Further, operational time was reduced from 3 days (conventional slickline memory or e-line logging performed during daylight operation) to 1 day (a combination of fiber-optic distributed temperature sensing and production log in a single run). The diagnosis of production system issues was completed in one shut-in and one flowing condition, thereby reducing the risk of HSE exposure with multiple flowing conditions (to simulate the leak while the conventional production logging tool is moved to different depths in the well). Additional insight on leak quantification was confirmed from the production log data, where one leak was noted at the tubing collar while the other leak was noted a few meters above the tubing collar. This observation was substantial in deciding whether to proceed with tubing patch or replace the entire production tubing. The novel operational approach affirms fiber-optic distributed temperature measurement's versatility in solving critical issues of operation time and reducing HSE exposure while delivering decisive information on production system issues. The paper serves as a staging area for other applications of similar nature to unlock even wider horizons for distributed temperature sensing measurement.
- Well Completion > Completion Monitoring Systems/Intelligent Wells > Downhole sensors & control equipment (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
Abstract Equivalent circulation density of the fluid circulation system in drilling rigs is determined by the frictional pressure losses in the wellbore annulus. Flow loop experiments are commonly used to simulate the annular wellbore hydraulics in the laboratory. However, proper scaling of the experiment design parameters including the drill pipe rotation and eccentricity has been a weak link in the literature. Our study uses the similarity laws and dimensional analysis to obtain a complete set of scaling formulae that would relate the pressure loss gradients of annular flows at the laboratory and wellbore scales while considering the effects of inner pipe rotation and eccentricity. Dimensional analysis is conducted for commonly encountered types of drilling fluid rheology, namely, Newtonian, power-law, and yield power-law. Appropriate dimensionless groups of the involved variables are developed to characterize fluid flow in an eccentric annulus with a rotating inner pipe. Characteristic shear strain rate at the pipe walls is obtained from the characteristic velocity and length scale of the considered annular flow. The relation between lab-scale and wellbore scale variables are obtained by imposing the geometric, kinematic, and dynamic similarities between the laboratory flow loop and wellbore annular flows. The outcomes of the considered scaling scheme is expressed in terms of closed-form formulae that would determine the flow rate and inner pipe rotation speed of the laboratory experiments in terms of the wellbore flow rate and drill pipe rotation speed, as well as other parameters of the problem, in such a way that the resulting Fanning friction factors of the laboratory and wellbore-scale annular flows become identical. Findings suggest that the appropriate value for lab flow rate and pipe rotation speed are linearly related to those of the field condition for all fluid types. The length ratio, density ratio, consistency index ratio, and power index determine the proportionality constant. Attaining complete similarity between the similitude and wellbore-scale annular flow may require the fluid rheology of the lab experiments to be different from the drilling fluid. The expressions of lab flow rate and rotational speed for the yield power-law fluid are identical to those of the power-law fluid case, provided that the yield stress of the lab fluid is constrained to a proper value.
- Well Drilling > Drilling Operations (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
Enhancing Production Through Well Interventions Using End-to-End Evaluation Methodology
Oatey, Mark (Chrysaor) | Duff, Fay (Chrysaor) | Emslie, Neil (Chrysaor) | Christie, Steven (Chrysaor) | Rikabi, Rida (Chrysaor) | Henderson, Peter (Chrysaor) | Singh, Kamaljeet (Schlumberger) | Kumar, Apoorva (Schlumberger) | Agrawal, Gaurav (Schlumberger) | Dutta, Shaktim (Schlumberger) | Bajwa, Haroon (Schlumberger)
Abstract In this paper, an end-to-end evaluation service using well historical production, petrophysics and reservoir data combined with new logs to perform well intervention solution methodology is followed. Across four wells, production logging data is acquired and analysed to understand the current performance of different heterogeneous layers. Combining this with openhole data, additional perforations and reperforations are planned. Perforations are carried out using deep-penetration charges to create a larger and deeper flow path between the reservoir and the wellbore. Post-perforation production logs are carried out, and the data is analysed to understand the effectiveness of newly perforated layers. Detailed production enhancement of all four wells is discussed in the paper. The majority of the wells displayed a significant increase in production when compared with pre-intervention flow rates. Minor scale buildup in the production liner was observed during pre-perforation production log data which was observed to be cleared during post-perforation production log data. The deliverability of the wells had also gone up, with similar production rates at much higher bottomhole pressure compared with pressures before intervention. This also confirmed the effectiveness of deep-penetration charges during perforation in providing better conduit from reservoir to wellbore. Additional perforations carried out, based on the heterogeneity of the reservoir and combining the openhole data, proved to be highly effective, with high deliverability observed from these new layers. In conclusion, a successful production enhancement of these low-flow-rate gas condensate wells was achieved with an end-to-end solution. A highly heterogeneous reservoir with multiple thinly bedded layers presented challenges in understanding their productivity. The combination of pre-perforation production log and post-perforation production log enabled evaluation of the deliverability of the complex heterogeneous reservoir. Further, production enhancement from each reperforated interval was confirmed using a direct measurement, i.e., production log data instead of relying on surface flow rates to better understand the downhole dynamics.
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Witch Ground Graben > Block 16/27b > Britannia Field (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Witch Ground Graben > Block 16/27a > Britannia Field (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Witch Ground Graben > Block 16/26 > Britannia Field (0.99)
- (2 more...)
- Well Completion > Completion Installation and Operations > Perforating (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
Abstract While pressure transient analysis (PTA) is a proven interpretation technique, it is mostly used on buildups because drawdowns are difficult to interpret. However, the deferred production associated with buildups discourages regular application of PTA to determine skin and identify boundary conditions. Several case studies are presented covering a range of well configurations to illustrate how downhole transient liquid rate measurements with electrical submersible pump (ESP) gauges enable PTA during drawdown and therefore real-time optimization. The calculation of high-frequency transient flow rates using ESP gauge real-time data is based on the principle that the power absorbed by the pump is equal to that generated by the motor. This technique is independent of fluid specific gravity and therefore is self-calibrating with changes in water cut and phase segregation. Analytical equations ensure that the physics is always respected, thereby providing the necessary repeatability. The combination of downhole transient high-frequency flow rate and permanent pressure gauge data enables PTA using commonly available analytical techniques and software, especially because superposition time is calculated accurately. The availability of continuous production history brings significant value for PTA. It makes it possible to perform history matching and to deploy semilog analysis using an accurate set of superposition time functions. However, the application of log-log analysis techniques is usually more challenging because of imperfections in input data such as noise, oversimplified production history, time-synchronization issues, or wellbore effects. These limitations are solved by utilizing high-frequency downhole data from ESP. This is possible first as superposition time is effectively an integral function, which dampens any noise in the flow rate signal. Another important finding is that wellbore effects in subhydrostatic wells are less impactful in drawdowns than in buildups where compressibility and redistribution can mask reservoir response. Key reservoir properties, in particular mobility, can nearly always be estimated, leading to better skin factor determination even without downhole shut-in. Finally, with the constraint of production deferment eliminated, drawdowns can be monitored for extended durations to identify boundaries and to perform time-lapse interpretation more efficiently. Confirming a constant pressure boundary or a change in skin enables more effective and proactive production management. In all cases considered, a complete analysis was possible, including buildup and drawdown data comparison. With the development of downhole flow rate calculation technology, it is now possible to provide full inflow characterization in a matter of days following an ESP workover, without any additional hardware or staff mobilization to the wellsite and no deferred production. More importantly, the technique provides the necessary information to diagnose the cause of underproduction, identify stimulation candidates, and manage drawdown.
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
Comprehensive Analysis of Production Loggings in Fuling Shale Gas Play in China
Liu, Yaowen (Sinopec Fuling Shale Gas Exploration and Development Company, China) | Pang, Wei (State Key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development, Sinopec Research Institute of Petroleum Engineering, China) | Shen, Jincai (Sinopec Fuling Shale Gas Exploration and Development Company, China) | Mi, Ying (Sinopec Fuling Shale Gas Exploration and Development Company, China)
Abstract Fuling shale gas field is one of the most successful shale gas play in China. Production logging is one of the vital technologies to evaluate the shale gas contribution in different stages and different clusters. Production logging has been conducted in over 40 wells and most of the operations are successful and good results have been observed. Some previous studies have unveiled one or several wells production logging results in Fuling shale gas play. But production logging results show huge difference between different wells. In order to get better understanding of the results, a comprehensive overview is carried out. The effect of lithology layers, TOC (total organic content), porosity, brittle mineral content, well trajectory is analyzed. Results show that the production logging result is consistent with the geology understanding, and fractures in the favorable layers make more gas contribution. Rate contribution shows positive correlation with TOC, the higher the TOC, the greater the rate contribution per stage. For wells with higher TOC, the rate contribution difference per stage is relatively smaller, but for wells with lower TOC, it shows huge rate contribution variation, fracture stages with TOC lower than 2% contribute very little, and there exist one or several dominant fractures which contributes most gas rate. Porosity and brittle minerals also show positive effect on rate contribution. The gas rate contribution per fracture stage increases with the increase of porosity and brittle minerals. The gas contribution of the front half lateral and that of latter half lateral are relatively close for the "upward" or horizontal wells. However, for the "downward" wells, the latter half lateral contribute much more gas than the front half lateral. It is believed that the liquid loading in the toe parts reduced the gas contribution in the front half lateral. The overview research is important to get a compressive understanding of production logging and different fractures’ contribution in shale gas production. It is also useful to guide the design of horizontal laterals and fractures scenarios design.
- Asia > China (1.00)
- North America > United States > Texas (0.95)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play > Shale Gas Play (1.00)
- Geology > Mineral (1.00)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Pennsylvania > Appalachian Basin > Marcellus Shale Formation (0.99)
- (4 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
A New Model for Predicting Liquid Loading in Shale Gas Horizontal Wells
Zhou, Chao (Sinopec Research Institute of Petroleum Engineering) | He, Zuqing (Sinopec Research Institute of Petroleum Engineering) | Chen, Yashu (Sinopec Research Institute of Petroleum Engineering) | Wang, Zhifa (Sinopec Tech Middle East LLC) | Mulunjkar, Amol (Sinopec Tech Middle East LLC) | Zhao, Weishu (Sinopec Tech Middle East LLC)
Abstract Current critical flow rate models fail to accurately predict the liquid loading statuses of shale gas horizontal wells. Therefore, a new critical flow rate model for the whole wellbore of shale gas horizontal wells is established. The results of the new model are compared to those of current models through the field case analysis. The new model is based on the dynamic analysis and energy analysis of the deformed liquid-droplet, which takes into account the liquid flow rate, the liquid-droplet deformation and the energy loss caused by the change of buildup rate. The major axis of the maximum stable deformed liquid-droplet is determined based on the energy balance relation. Meanwhile, the suitable drag coefficient equation and surface tension equation applied to shale gas horizontal wells are chosen. Finally, the critical flow rate equation is established and the maximum critical flow rate of the whole wellbore is chosen as the criterion for liquid loading prediction. The precision of liquid loading prediction of the new model is compared to those of the four current models, including Belfroid's model, modified Li's model, liquid film model and modified Wang's model. Field parameters of 29 shale gas horizontal wells are used for the comparison, including parameters of 18 unloaded wells, 2 near loaded-up wells and 9 loaded-up wells. Field case analysis shows that the total precision of liquid loading prediction of the new model is 93.1%, which is higher compared to those of the current four models. The new model can accurately predict the liquid loading statuses of loaded-up wells and near loaded-up wells, while the prediction precision for unloaded wells is high enough for the field application, which is 88.9%. The new model can be used to effectively estimate the field liquid loading statuses of shale gas horizontal wells and choose drainage gas recovery technologies, which considers both the complex wellbore structure and the variation of flowback liquid flow rate in shale gas horizontal wells. The results of the new model fill the gap in existing studies and have a guiding significance for liquid loading prediction in shale gas horizontal wells.
- North America > United States (0.88)
- Asia (0.68)
- Asia > China > Sichuan > Sichuan Basin > Chuanzhong Block > Sichuan Field (0.99)
- North America > United States > Louisiana > China Field (0.97)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- Production and Well Operations > Artificial Lift Systems > Gas well deliquification (1.00)
Sensor Ball: Modernized Logging
Buzi, Erjola (Aramco Services Company) | Seren, Huseyin (Aramco Services Company) | Hillman, Thomas (Aramco Services Company) | Thiel, Timothy (Aramco Services Company) | Deffenbaugh, Max (Aramco Services Company) | Bukhamseen, Ahmed (Saudi Aramco) | Zeghlache, Mohamed Larbi (Saudi Aramco)
Abstract The latest development in the electronics and manufacturing industry has enabled work towards the modernization of oil-field instruments. As a part of this trend, it is the time to invent and design small size oil-field instruments that could be much more practical to handle, easy to use, and less costly. High temperatures and pressures of the downhole environment make it very challenging to design and further develop such downhole instruments. To create such apparatuses, a thorough study of downhole conditions needs to be done upfront. This study will further help to define the design specifications and requirements. By targeting liquid wells in Saudi Arabia, we have overcome the challenges posed by the harsh downhole environment and managed to design and manufacture a hand-held device called ‘Sensor Ball’ and tested it in the field.
- Well Drilling (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (0.98)
- Well Completion (0.72)
Innovative Spinner Design Aids in Flow Characterization and Production Optimization of a Multistage Frac Well
Agrawal, Gaurav (Schlumberger) | Kumar, Ajit (Schlumberger) | Singh, Rajvardhan (Schlumberger) | Gupta, Alekh (Schlumberger) | Kundi, Puneet Kanwar Singh (Schlumberger) | Mukerji, Parijat (Schlumberger)
Abstract An operator working in Indian western land reservoirs, planned to develop a low-permeability, high potential reservoir with hydraulic fracturing. In the pilot project, production behavior of the initial wells was below expectation. As a diagnostic procedure few of the wells were attempted with memory coiled tubing-assisted production logging to record production log data and identify the root cause behind poor performance. Apart from the horizontal trajectory, major challenges associated with this approach included the low flow rate (150-200bbl) and expectation of frac fluid inside the wellbore due to inadequate cleaning. As a result, all the attempts for effective diagnosis were inconclusive. Moreover, absence of critical input such as individual stage frac evaluation demanded attention in order to optimize completion quality (CQ) and conclude effective fracturing and completion strategy prior to full field development planning. Addressing the challenges and with an aim to provide the critical inputs required for reservoir characterization and production optimization, a multi-spinner production logging tool with new innovative spinner design and multi-electrical and optical sensors were proposed on cased-hole tractor in order to resolve the complex flow profiles associated with the low flow rates and horizontal well trajectory. The newly configured spinners with innovative spinner design material lowered the spinner threshold from 2ft/min to 1ft/min for multipass logging in lab tests. It also optimized the magnetic field distribution to ensure less accretion of debris on the spinner (causing spinners to clog) without compromising measurement accuracy. With well production being 200 bbl at the time of logging, the multi-spinner survey with innovative spinner design clearly resolved the dynamic changes across the borehole during multi bean data acquisition. Overcoming the major interpretation challenge of isolating the dynamic changes in the wellbore due to borehole trajectory and due to fracturing stage, individual stage frac flow contributions were evaluated. Stage frac productivity correlated very well with the frac operation parameters, reservoir quality and completion quality. Apart from individual contributions, key findings such as activation of few frac stages at high drawdown pressures, increasing gas contribution from toe to heel and resolving presence of leftover frac fluid in the well, exceeded the expectations set by the client in terms of the objectives vs. results. This success clearly demonstrated that knowledge of downhole dynamics for horizontal trajectory is vital. This is not limited only to address the individual well requirement, but an integrated approach would help to optimize future wells through better understanding of reservoir productivity vs frac operation and completion quality (CQ).
- Well Completion > Hydraulic Fracturing (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
Water Injection Profiling Using Fiber Optic Sensing by Applying the Novel Pressure Rate Temperature Transient PTRA Analysis
Al-Hashemi, Mohammed (Shell) | Spivakovskaya, Daria (Shell) | Moes, Evert (Shell) | Panhuis, Peter in ‘t (PDO) | Hemink, Gijs (PDO) | Shako, Valery (Schlumberger) | Kortukov, Dmitry (Schlumberger)
Abstract Fiber Optic Systems, such as Distributed Temperature Sensing (DTS), have been used for wellbore surveillance for more than two decades. One of the traditional applications of DTS is injectivity profiling, both for hydraulically fractured and non-fractured wells. There is a long history of determining injectivity profiles using temperature profiles, usually by analyzing warm-back data with largely pure heat conduction models or by employing a so-called "hot-slug" approach that requires tracking of a temperature transient that arises at the onset of injection. In many of these attempts there is no analysis performed for the key influencing physical factors that could create significant ambiguity in the interpretation results. Among such factors we will consider in detail is the possible impact of cross-flow during the early warm-back stage, but also the temperature transient signal that is related to the location of the fiber-optic sensing cable behind the casing when the fast transient data are used for interpretation such as the "hot slug" during re-injection. In this paper it will be shown that despite all such potential complications, the high frequency and quality of the transient data that can be obtained from a continuous DTS measurement allow for a highly reliable and robust evaluation of the injectivity profile. The well-known challenge of the ambiguity of the interpretation, produced by the interpretation methods that are conventionally used, is overcome using the innovative "Pressure Rate Temperature Transient Analysis" method that takes maximum use of the complete DTS transient data set and all other available data at the level of the model-based interpretation. This method is based on conversion of field measurements into injectivity profiles taking into account the uncertainty in different parts of the data set, which includes the specifics of the DTS deployment, the uncertainty in surface flow rates, and possible data gaps in the history of the well. Several case studies will be discussed where this approach was applied to water injection wells. For the analysis, the re-injection and warmback DTS transient temperature measurements were taken from across the sandface. Furthermore, for comparison, injection profiles were also recorded by conventional PLTs in parallel. This case study will focus mostly on the advanced interpretation opportunities and the challenges related to crossflow through the wellbore during the warm-back phase, related to reservoir pressure dynamics, and finally related to the impact of the method of DTS deployment. In addition to describing the interpretation methodology, this paper will also show the final comparison of the fiber-optic evaluation with the interpretation obtained from the reference PLTs.
- North America > United States > Texas (0.46)
- Asia > Middle East > Saudi Arabia (0.46)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.70)
Abstract In a highly sensitivity oil and gas upstream conditions, there is a need for a real-time interaction platform to cope with harsh environment. The oil and gas business faces data validity constraints in terms of reliability, accuracy, and repeatability to name a few. The Internet of Sensors (IoS), with appropriate utilization, will play a major role in the industry's digital transformation. Predetermined IoS platforms with applicable characteristics are functioning in critical oil and gas environment applications. For example, some oil and gas wells produces harmful gases, like hydrogen sulfide (H2S). Fiber-optic sensors can be used as a leak detection tool for H2S resistance to inform oil and gas curfew if harmful gas is detected at the well site using cloud computing. Scale and corrosion monitoring of external pipelines is one of the integrity challenges. Ultrasonic sensors are embedding for real-time scale thickness feedback and corrosion monitoring by utilizing wireless transmission directly to end-user devices. A paradigm shift is happening with the IoS applications in oil and gas operations for sensitivity, reliability, and accuracy that will add intelligence, smart decisions, and control to the operational landscape. A comprehensive review of the art in oil and gas IoS presented in this paper. The target is to evaluate state-of-the-art IoS platforms for hazardous environments such as oil and gas facilities in terms of type of sensors used, applicability, functionalities, linearity, and accuracy, type of output signals, outputs range, and materials used. This work establishes classification and comparison of the IoS for better data collection, communication, connectivity, observation, and reporting in the world of oil and gas sensors. The IoS platforms classified and compared in tables consisting of different characteristics for the best-suited IoS platform designs in oil and gas appliance applications. This will provide references for IoS design engineers.
- Asia > Middle East > Saudi Arabia (1.00)
- Asia > Middle East > Yemen (0.95)
- Africa > Sudan (0.95)
- (3 more...)