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Collaborating Authors
SPE Reservoir Characterisation and Simulation Conference and Exhibition
Phase-Field Modeling of Spontaneous Imbibition in Tight Porous Media
Wang, Daigang (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, Beijing 102249, China) | Ma, Yushan (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, Beijing 102249, China) | Song, Kaoping (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, Beijing 102249, China) | Wei, Chenji (Research Institute of Petroleum Exploration and Development, PetroChina, Beijing 100083, China) | Zhang, Jing (Research Institute of Petroleum Exploration and Development, PetroChina, Beijing 100083, China) | Yu, Tao (Research Institute of Petroleum Exploration and Development, PetroChina, Beijing 100083, China) | Song, Yang (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, Beijing 102249, China)
Abstract Tight oil reservoirs generally have no natural productivity due to the influence of micro/nano pore structure. The horizontal well volume fracturing technique is widely used to achieve effective development of this type of reservoirs. The remaining oil in matrix pores is mainly produced by spontaneous imbibition in the actual soaking and flowback process. Due to the great limitation of observation scale, the traditional experimental testing methods cannot accurately characterize the distribution and production of remaining oil at nano-scale in tight oil reservoirs, the microscopic mechanism of spontaneous imbibition has not been clearly explained. In order to resolve those issues, a two-dimensional geometric model is firstly established based on the raw images of typical tight rock sample obtained by a highresolution CT imaging device. A novel pore-scale mathematical model of spontaneous imbibition in tight porous media is developed from the Navier-Stokes equations, which is numerically solved by using the phase-field method. Compared with the analytical results of the single-pipe imbibition model, the reliability of the proposed method was fully validated. Based on the analysis of the spontaneous imbibition microscopic dynamic phenomena, the influences of wettability, oil-water interfacial tension, oil-water viscosity ratio and micro-fracture morphology on the remaining oil in micro/nano pores and spontaneous imbibition recovery are further explored. Results show that, the results obtained by the phase-field modeling of spontaneous imbibition are in good agreement with the analytical solution of the single-pipe imbibition model, and the front evolution process of oil-water interface during spontaneous imbibition is accurately described. The pore-scale dynamic events of oil droplets, snap-off, cross flow and coalescence are well characterized. The oil/water interfacial tension has little effect on spontaneous imbibition recovery, but significantly affects the imbibition time. The smaller the oil/water interfacial tension is, the longer the imbibition time is. Wettability and oil-water viscosity ratio can exert a significant effect on imbibition recovery. The existence of micro-fractures increases the imbibition contact area, improves the fluid flow capacity, and significantly improves the degree of remaining oil production and imbibition recovery. A novel methodology to study two-phase fluid flow during spontaneous imbibition in tight porous media is proposed using the phase-field method in this work, which can provide a theoretical basis for understanding the underlying fluid flow dynamics during fracturing, soaking and flowback process of tight oil reservoirs.
Abstract The cluster spacing was set up to 700 ft in diffrent shale formations including Bakken and Barnet shales. Howerver, tight cluster spacing was applied in apart in Eagle Ford and DJ Basin for cluster spacing up to 15 ft. The tight fracture spacing was applied to ais to increase the initial production rate. However, a higher initial production rate is at the expense of higher operation and completion costs in addition to operational complexity. This study presents an combined workflow to calculate the percent of interference and its effect on the well performance in addition estimate the acceptable interference degree that provides the highest well profitability. Analytical rate transient analysis (RTA) and reservoir numerical simulation were combined to estimate the ratio of the effective fracture surface area (ACe) for hydrocarbon production to the actual stimulated fracture area (ACa) from the numerical simulation. The degree of interference was calculated by (1- ACe/ACa). The economic study was added to the integrated workflow to estimate the degree of interference and the optimum spacing based on the profitability of the well. This study presents an integrated workflow to quantify the degree of cluster interference as a function of spacing. The workflow was integrated with an economic model to estimate the acceptable interference percent to have a higher NPV. The higher the stage number and tighter cluster spacing, the higher the cluster interference will be. The acceptable interference percent is a function of formation properties and economic parameters. The acceptable interference percent was found to be 16% in the case of 0.0001md, 2.5$/Mscf. Increasing the formation permeability increases the acceptable interference percent to accelerate production and increase the recovery. As the gas price increases, tighter spacing is recommended, where, at 8$/Mscf, the NPV was continuously increasing up to the lowest spacing in this study of 20 ft. This study provides an integrated workflow to quantify the interference percent and the acceptable percent as a function of cluster spacing, formation properties, and economic analysis in order of increasing the well profitability.
- Asia (0.93)
- North America > United States > Texas (0.69)
- 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)
- (27 more...)
Abstract In this study, we investigate the use of deep learning-based and kernel-based proxy models in nonlinearly constrained production optimization and compare their performances with directly using the high-fidelity simulators (HFS) for such optimization in terms of computational cost and optimal results obtained. One of the proxy models is embed to control and observe (E2CO), a deep learning-based model, and the other model is a kernel-based proxy, least-squares support-vector regression (LS-SVR). Both proxies have the capability of predicting well outputs. The sequential quadratic programming (SQP) method is used to perform nonlinearly constrained production optimization. The objective function considered here is the net present value (NPV), and the nonlinear state constraints are field liquid production rate (FLPR) and field water production rate (FWPR). NPV, FLPR, and FWPR are constructed by using two different types of proxy models. The gradient of the objective function as well as the Jacobian matrix of constraints are computed analytically for the LS-SVR, whereas the method of stochastic simplex approximated gradient (StoSAG) is used for optimization with E2CO and HFS. The reservoir model considered in this study is a two-phase, three-dimensional reservoir with heterogeneous permeability which is taken from the SPE10 benchmark case. Well controls are optimized to maximize the NPV in an oil-water waterflooding scenario. It is observed that all proxy models can find optimal NPV results like optimal NPV obtained by HFS with much less computational effort. Among proxy models, LS-SVR is found to be less computationally demanding in the training process. Overall, both proxy models are orders of magnitude faster than numerical models in the prediction. We provide new insights into the accuracy and prediction performances of these machine learning-based proxy models for 3D oil-water systems as well as their efficiency in nonlinearly constrained production optimization for waterflooding applications.
Abstract Gas oil Gravity Drainage (GOGD) process is one of the highly efficient recovery mechanism in heavily fractured carbonate reservoirs. The driving force is the gravity, the oil is moving down from the matrix block through fractures until it reaches the producers. To ensure optimum offtake from the reservoir through the horizontal wells the oil rim need to be stabilized and very well managed through the gas injection, offtake/intake balance, aquifer pump off. A key challenge of optimizing the gas injection as well as the offtake from the horizontal wells to achieve effective GOGD recovery is to ensure that a minimum oil rim thickness is maintained, and that oil rim is kept at the same depth as the oil production well. If not; When the oil rim moves down, the well will produce gas instead of oil, therefore resulting in deferment and inefficient GOGD recovery. When the oil rim moves up, the well will produce water from the fracture system, therefore resulting in deferment and significant time to recover the oil rim to the correct depth. A typical monitoring method for the fracture fluid fill is to run "gradio" surveys in dedicated observation wells to measure the fGOC and fOWC (where "f" represent the fracture system contacts i.e. fractured gas oil contact and fractured oil water contact rather than the matrix contacts). Also the fluid movement in matrix can be monitored by Pulsed-Neutron logging, in combination with Open-hole logs that have been acquired at different times through the development. In addition to the logging methods, GOGD Flow Unit characterization was introduced to depict the effect of the intake/offtake changes and oil rim movement within the GOGD system along with a surveillance strategy focusing on reservoir optimization. Fluid contact visualization plots were generated for each flow unit which give a clearer picture in how effective is the current GOGD system and the future reservoir development and optimization. More than 5 flow units with almost 150 active wells,3 gradio wells and 5 pulsed neutron log data were reviewed, to generate fluid contact visualization plots and justify flow unit production behavior. This analysis initiative helped to depict the effect of the intake/offtake changes and oil rim movement within the GOGD system. This work also led to adding additional development opportunities like placement of future new wells or adding perfs /carrying out zone change in existing closed in wells either to produce oil or to pump off water. This eventually fed into the reservoir optimization and surveillance strategy.
- Asia > Middle East > Oman (0.42)
- Asia > Middle East > UAE (0.28)
Abstract Forecasting in unconventional reservoirs is a challenging task due to its complex physics. While decline curve analysis (DCA) is the ubiquitous workhorse for forecasting production rates, it often is not adequate in several scenarios without consideration of physics. Alternately, full-physics reservoir simulation models are equipped with comprehensive physics; however, they are often tedious, time-consuming, and data-hungry due to their underlying requirements on geological modeling, fracture modeling and model calibration. The goal of this work is to apply a reduced-physics framework (RGNet) for modeling, conditioning, and forecasting unconventional reservoirs in an efficient manner, while preserving the fundamental flowing physics to ensure prediction accuracy. Based on the concept of diffusivity of time of flight, RGNet models the drainage volume of a target well using a set of 1D grid blocks in lieu of a detailed 3D grid system, which significantly reduces the complexity of the system and enables faster model runtime. Since RGNet constructs a reservoir model with a completely different frame of reference by simply following pressure evolution patterns originating from the well, it removes the burden of geological/fracture modeling. The parameters defined in the 1D grids are common reservoir properties that are physically interpretable such as transmissibilities and pore volumes which are calibrated by history matching routinely measured data (rate, pressure). In addition to common reservoir-flow physics, pressure-dependent properties are considered inside the framework as the physics specific to unconventional reservoirs. The proposed framework is applied for multiple field examples with multi-phase production including gas and oil reservoirs. The field examples demonstrate that we can obtain reasonable history matches under single-well and multi-well scenarios. Reservoir properties are reasonably characterized, including relative permeabilities, well indices, pore-volumes, transmissibilities and well interference. Furthermore, the tests on oil reservoirs show good prediction of gas-oil ratio changes, which is typically difficult to achieve using analytical or empirical approaches. By using an ensemble-based history-matching algorithm, RGNet also provides multiple history-matches and forecasts for uncertainty analysis. As RGNet uses a parsimonious method for modeling the reservoir, the runtime of one forward model is only a few seconds for all the examples presented, which is much faster than a full-physics model. RGNet provides an efficient way to model, history match, characterize and forecast unconventional reservoirs. It provides a generic framework so any relevant physics can be incorporated. As common reservoir properties are used to parameterize reservoirs, the results are easily interpretable. The superior efficiency of RGNet makes it suitable as a fit-for-purpose tool for well performance analysis and continuous production optimization in unconventionals.
- 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)
- (22 more...)
Maximizing Value from Geosteering Efficiency by Integrating Real-Time Petrophysical Analysis
Kundu, Ashish (ADNOC Onshore) | Raza, Taufique Ahmad (ADNOC Onshore) | Deng, Lichuan (ADNOC Drilling) | Soliman, Ahmed Mohamed (ADNOC Drilling) | Elabsy, Eslam (ADNOC Drilling) | Zemiti, Sarah (ADNOC Drilling) | Alhammadi, Alyazia (ADNOC Onshore)
Abstract Conventional geo-steering approach use raw logging measurements to define wellbore positioning within the reservoir while drilling. The geo-steering specialist usually compares real-time logs to modelled logs (GR/Density/Neutron/Resistivity) and the geological model is then adjusted to make real-time decisions to deliver the well objectives. This conventional method is applicable to most reservoir conditions. However, it may be insufficient or inappropriate in heterogeneous reservoirs or wells with complex geological settings, potentially resulting in wells being sub-optimally placed and reducing the value of reservoir sections in terms of productivity. This paper aims to showcase a Petrophysics-based Geo-steering approach to maximize the value of reservoir sections. Geo-steering aims to place the well trajectory in the lithology with optimum storage capacity, flow capacity and hydrocarbon saturation. The method of log-to-log comparison is popular for its simplicity and speed of use in real-time but is not enough for certain scenarios. For example, the real-time log response can be very different from modelled log response in the presence of gas or very light oil, irrespective of petrophysical properties (porosity/permeability) being similar. Moreover, real-time Sw estimation would be required in addition to porosity to minimize the risk of drilling a producer into water bearing intervals. In fact, the comparison between petrophysical parameters is more appropriate to heterogeneous reservoirs or wells with complicated geology. This approach requires good co-ordination between geologist, petrophysicist and geo-steering specialist. Prior to drilling, the petrophysical model from offset wells should be defined and used to derive porosity, permeability and saturation. While drilling, the petrophysical properties are then interpreted in real-time and based on the comparison between modelled and real-time petrophysical properties, decisions are to be made with respect to the well objectives. An example with strong gas effect in a carbonate reservoir from Abu Dhabi is presented to demonstrate this novel approach. Real-time density/neutron does not have good correlation with modelled density /neutron due to gas effect. Such poor correlation can be attributed to proximity to a Gas Oil Contact (GOC) and dynamic invasion, complicating the real-time geo-steering. However, real-time total porosity from log analysis correlates very well with modelled total porosity, providing confidence in wellbore positioning and allowing the geologist and the geo-steering specialist to make the correct real-time decision to place the well in the optimum stratigraphic position in order to meet the well objectives. Only conventional logs are utilized in this case, but if real-time NMR and resistivity image interpretation are available, it will provide additional information in term of permeability, secondary porosity and irreducible water saturation to aid efficient geo-steering.
- Asia > Middle East > UAE > Thamama Group > Shu'aiba Formation (0.99)
- Asia > Middle East > UAE > Abu Dhabi > Arabian Gulf > Rub' al Khali Basin > Abu Dhabi Field (0.98)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Upper Marrat Formation (0.98)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Sargelu Formation (0.98)
Success in Complex Channel Sand Reservoir Development Driven by New Generation of Ultra-High-Definition Multilayer Mapping-While-Drilling Service and Hybrid Rotary Steerable System
Yang, Bin (Sinopec Sheng Li Ocean) | Li, Tong (SLB) | Wang, Fei (SLB) | Wang, Feng Hai (SLB) | Li, Shu Zhong (SLB) | Wu, Kai (SLB) | Hu, Zhong (SLB) | Wang, Li (SLB) | Chen, Yao (SLB) | Liu, Qi Xun (SLB) | Zhang, Yan Xing (SLB) | Maalouf, Janine (SLB)
Abstract Accurate real-time characterization of complex channel sand reservoir is very critical for horizontal well drilling and production improvement. CB block located in the southwest part of Bohai Bay which is the main offshore block for SINOPEC Sheng Li. This block is featured by braided river and fluvial deposition environment. The operator faced challenges during horizontal drilling, such as thin sand channels, inner-beds development, severe lateral change, unstable sand structure and low sand connectivity. A horizontal well drilling campaign was launched in 2021. Through considerable data assessment and feasibility study, the new generation of Ultra-High-Definition multilayer mapping-while-drilling service and rotary steerable system (RSS) as an integrated solution package was deployed to this project to overcome above challenges. Without any a-priori assumptions, the new generation service doubles depth of detection (DOD) range compared with previous bed-boundary detection services, delivers clearer boundary delineation, and is capable of remotely identifying the quantitative subsurface features, including layersโ numbers, resistivity and anisotropy distribution, thickness, and dip etc. Meanwhile, the truly hybrid RSS with near bit measurements ensures accurate and smooth trajectory control and reduces the drilling risk in the soft formation. The pilot project was successfully completed. With the help from real-time measurements combined with seismic data, and by utilizing the advanced inversion advantage, this technology could depict whole individual sand bodies and their mutual lateral contact relationship clearly, which not only can optimize the reservoir exposure rate but also provide a better way for detailed reservoir characterization. Four wells were geosteered for a total of1026m with 96.1% reservoir exposure rate. Primary production from these 4 horizontal wells exceeded the expected production by 40% with only 10% water cut. This innovative solution demonstrates its advantage on optimizing a complex channel sand drilling and development. The authors believe that the fit-for-purpose solution could be expanded to other similar projects by showcasing the distinctive case studies in this paper.
- Asia > China (1.00)
- Asia > Middle East (0.94)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.71)
- Geology > Sedimentary Geology > Depositional Environment > Continental Environment > Fluvial Environment (0.49)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying (0.89)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > China Government (0.35)
- Asia > China > Shandong > North China Basin > Shengli Field (0.99)
- Asia > China > Bohai Bay > Bohai Basin > Huanghua Basin > Chengdao Field (0.99)
- Asia > China > Bohai Basin (0.99)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Drilling > Drilling Equipment > Directional drilling systems and equipment (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
Abstract The availability of a simple and robust flow allocation system is of primary importance for reservoir management since it provides oil, water, and gas production for each well. The low frequency of well separator tests and the difficulties in performing regular maintenance of multiphase flow meters have led to the development of Real Time Virtual Flow Meter (RTVFM) in Eni, a numerical solution to obtain real time flow rate estimation from pressure/temperature gauges measurements. This paper discusses the implementation and application of a novel RTVFM algorithm that increases the accuracy, stability, and robustness of the existing numerical tools even in case of extreme oil field environment with significant uncertainties. Current Virtual Meter algorithms are based on fluid dynamic simulators which calculate the pressure drops through wellbore, choke, and flowlines; the algorithm can be run in real time to find the optimal production rates that minimize the error between physical pressure readings and the calculated ones. In this work, a constraint is added to the system by including the temperature matching in the objective function, further improving the tool reliability. An accurate heat transfer characterization of the well has been implemented to predict the temperature changes along the wellbore during time, as well as the thermal effect due to pressure variations (Joule-Thompson effect). The effectiveness of the implemented algorithm has been proven by its application on a few offshore oil producers. In the chosen wells, equipped with dedicated MPFMs, the production measurements are not always reliable and RTVFM can be a valid support tool for back allocation. However, the flow rate estimation can be affected by significant uncertainties like production parameters variability (water cut and gas oil ratio) and fluid properties variation due to gas re-injection or artificial gas lift. In this scenario, the proposed enthalpy balance model allows to find a unique solution for the flow rate estimation, while the algorithm based only on pressure readings can converge to multiple solution rates. Increasing the accuracy of RTVFM tool is imperative to allow a reliable back allocation process, even in case of MPFM unavailability, poor sensors data quality and highly variable fluid properties. This paper investigated how an advanced thermo-fluid dynamic model can improve Virtual Meter algorithms, thus reducing the uncertainties in the numerical flow rate estimation.
A Numerical Study of Mineral Dissolution in Deep Heterogeneous Carbonate Reservoirs: Implications for CO2 Geo-sequestration
Fathy, Ahmed (Khalifa University of Science and Technology) | Arif, Muhammad (Khalifa University of Science and Technology) | Adila, Ahmed Sami (Khalifa University of Science and Technology) | Raza, Arshad (King Fahd University of Petroleum & Minerals) | Mahmoud, Mohamed (King Fahd University of Petroleum & Minerals)
Abstract CO2 geo-sequestration has shown potential to mitigate global warming caused by anthropogenic CO2 emissions. In this context, CO2 can be immobilized in subsurface formations due to chemical dissolution/precipitation via mineral trapping. However, long-term mineralization involves interdependent complexity of dissolution and precipitation kinetics. In this study, a numerical approach is developed and implemented to analyze the effect of rock type, reservoir temperature, brine salinity on CO2 mineral trapping in compositionally distinct subsurface carbonate reservoirs. Here, we simulated field-scale models for three different subsurface reservoirsโ compositions (calcite, dolomite, and siderite) to assess the mineral trapping capacity. The base case of a 3D carbonate formation was created. The petrophysical parameters were then upscaled (Sw, Sg, K, and ฯ) to capture the subsurface conditions. Subsequently, CO2 mineral trapping capacity was computed for different rock compositions mimicking carbonate/brine/CO2 systems. Moreover, the CO2 geo-storage potential was assessed under reservoir temperature, salinity, storage duration, and cumulative injected CO2. The effect of reservoir mineralogy was analyzed via the amount of CO2 mineralized within 100 years of storage duration following 2 years of injection as a base case. The results revealed significant variation in storage capacity as the mineral type changed. In particular, 100% calcite surface showed the highest CO2 storage capacity compared to both dolomite and siderite. The results could be attributed to the distinction of each mineral in terms of its relative cations dissolve-out rate. Moreover, increasing the reservoir temperature resulted in a monotonic increase in mineralization potential with an insignificant increase in case of siderite. Notably, calcite outperformed both siderite and dolomite as a preferable medium for CO2 mineralization as the injection duration increased over both 100 and 200 years of storage. Additionally, the increase in salinity either significantly decreased the amount of CO2 mineralized in case of calcite and siderite or showed no effect at all in case of dolomite. This work provides a new insight for underpinning the effects of carbonate reservoir composition on CO2 mineral trapping capacity which has not been investigated much. Overall, the results showed that CO2 trapping in subsurface carbonates immobilized CO2 for a long-term stable geo-storage.
- Europe (1.00)
- North America > United States (0.68)
- Asia > Middle East (0.68)
- Geology > Mineral > Carbonate Mineral > Calcite (0.87)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Dolomite (0.87)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.69)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Health, Safety, Environment & Sustainability > Environment > Climate change (1.00)
- Health, Safety, Environment & Sustainability > Environment > Air emissions (1.00)
Internally Catalyzed Aqueous-Based Emulsion of Curable Epoxy Resin Sand Consolidation Treatment Extends Economical Production in Austria's Mature Oil and Gas Fields.
Trujillo, Erika Johana Tovar (Halliburton) | Santin, Yoann (Halliburton) | Ukoha, Obinnaya (Halliburton) | Caldarelli, Riccardo (Former Halliburton) | Maier, Robert (OMV Austria) | Kiss, Akos (OMV Austria) | Moertl, Monica (OMV Austria) | Zabel, David (OMV Austria)
Abstract Sand production is one of the major challenges for mature fields in Austria. With increasing water production, the severity of the sand migration augments, leading to the shut-in of the wells. Eliminating or substantially reducing sand production at the sand face is the most viable option to continue hydrocarbon production. The project's target was to research and apply a technically sound solution readily available in Europe, with reduced HSSE risks and little economic impact. To control intervention costs, it was decided to favor sand control solutions for rig-less interventions. Collaboratively, the teams evaluated formation rock consolidation with the help of an internally catalyzed aqueous-based emulsion of curable epoxy resin (ICABECER). Laboratory testing demonstrated the system's suitability for the target wells and confirmed the viability of the planned operations scheduled to deploy the treatment via coiled tubing (CT), as well as limiting concerns about permeability reduction. Finally, field operations of the application, clean-up, and production face were monitored and evaluated. The major concern when using resins to agglomerate sand grains in a reservoir rock is that the pore space is reduced, jeopardizing the rock permeability. Laboratory testing confirmed that the permeability of the rock can be retained. Due to the simplicity of the intervention, the treatment could be deployed with standard equipment keeping it within the budgetary constraints of very mature fields. To mitigate possible risks, wells having challenging production backgrounds and scheduled for plug and abandon were selected. In these wells, previous conventional sand control measures failed, such as gravel pack installations or attempting to produce sand and separate it on surface. Post-job results demonstrated that the in-situ consolidation generated a reduction of sand content to a level allowing production of the wells. During the clean-up period of the gas well, sufficient sand was produced to erode the choke. After the well start-up period, sand production was eliminated, and the well was returned to the target rate. Monitoring of solid contents in the flow and the evaluation of coupons confirmed the suitability of the technique to establish flow with acceptable risks contributing to economic success. The cost-effective ICABECER chemical treatment, along with the methodology, opens new opportunities for the asset to prolong well life and increase the overall recovery factor from the reservoir. Technical simplicity and the reduced environmental impact of the chemicals are key for resource-saving and sustainable operations in mature fields.
- North America > United States (1.00)
- Europe > Austria (0.88)
- Asia > Middle East > Saudi Arabia (0.28)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.72)
- Europe > Austria > Vienna > Vienna Basin (0.99)
- Europe > Austria > Lower Austria > Vienna Basin (0.99)