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Collaborating Authors
Results
Hydrocarbon Production Enhancement on the Field Apaika-Nenke by Applying Hydraulic Fracturing as a Tool to Optimize the Extraction of Reservoir M-2 Considered Initially as a Secondary Target
Salazar, F. (Schlumberger) | Vasconez, N. D. (Schlumberger) | Mayorga, C. J. (EP Petroecuador) | Pozo, M. F. (EP Petroecuador)
Abstract Due to reservoir conditions in the Apika-Nenke field, it was decided to carry out a hydraulic fracturing pilot project with the aim of maximizing production in the field. To achieve the objective, cores, image logs, pressure points, and sonic dipole logs were obtained to have the greatest amount of information available during the analysis and thus stimulate the reservoir to obtain the maximum potential. After the analysis of the laminated reservoirs, it was required to implement a technique that generates higher fracture conductivity to reduce the drawdown during production and improve the connection through the laminations. The successful implementation of channel fracturing led to this technique becoming the preferred completion method in the field for wells requiring stimulation. Three hydraulic fracturing treatments were performed in Apaika-Nenke field: one in 2015 and two in 2022. With continuous improvement in the perforating and fracturing technique, all jobs demonstrated outstanding production results. The implementation of hydraulic fracturing permits the production of this reservoir, which was considered a secondary target due to the low production results without fracturing.
- Geology > Rock Type > Sedimentary Rock (0.48)
- Geology > Geological Subdiscipline (0.47)
- Geology > Mineral (0.46)
- Geophysics > Seismic Surveying (0.67)
- Geophysics > Borehole Geophysics (0.54)
- South America > Ecuador > Oriente Basin (0.99)
- South America > Ecuador > Nueva Loja > Oriente Basin > Block 15 > Eden Yuturi Field > Napo Formation (0.99)
- Europe > United Kingdom > North Sea > Southern North Sea > Southern Gas Basin > Sole Pit Basin > B1 Well (0.99)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (0.75)
- Well Completion > Completion Installation and Operations > Perforating (0.47)
Abstract Measuring in-situ stresses in unconventional formations constitutes a cornerstone for reservoir-quality and completion-quality evaluation. Challenges of succeeding these tests are related to difficulties to break these formations and propagate the created fracture allowing fracture gradient estimation. Moreover, formation heterogeneities and properties anisotropy, often lead to model inaccuracies and expose drilling or fracking operations to "avoidable" failures. Hence earlier in unconventional reservoir exploration, successful in-situ stresses become a must have for geomechanical model and Fracturing design calibrations. While cross-discipline integration is key to building a representative and comprehensive MEMs, since the early 2000's, Wireline Formation Testers are used to collect localized in-situ stress measurements that constitute a valuable input to fine-tune MEMs. However, with limited knowledge and inadequate planning, these operations known as "Micro-Frac/Stress Testing" are often challenged with high failure rate, especially with legacy tools physical limits. A combination of a novel stochastic planning approach involving the multidomain integration of Petrophysics, Borehole-Images and Geomechanics, coupled with Cutting-Edge WFTs technologies significantly increases the success likelihood for Stress Testing providing thereby an unfailing calibration source for MEMs. This new approach allowed first to define the depths to test with higher rate of success to break the formations and then, to communicate to drillers and client supervisor the test duration and potential adjustment such as mud weight, to break the rock and propagate the created fractures in the formations. The above enables, from operational standpoint, successful risk-free stress test measurement, allowing the calibration of the Mechanical Earth Model and Frac Design in the hydrocarbons embedded Source Rocks across South Algerian Basins. Furthermore, stress mapping allowed the identification of a lateral variability of stress gradients within the same field, confirming the unreliability of single-stress-gradient based models and highlighting the importance of multi-well modeling of mechanical earth properties. By using a well calibrated MEMs leading to a keen understanding of stress state, chances of stimulation operations success were significantly increased. The benefit of utilizing this new method with advanced logging technologies among which the new generation of WFTs, combined with a multidomain data integration as well as a novel planning approach based on stochastic simulation enabled the achievement of a failure-free Stress Testing operations, yielding fine-tuning of MEMs in the challenging South Algerian Hot Shale. Through a keen knowledge of stress state, stimulation operations success was significantly increased.
- Research Report (0.68)
- Overview > Innovation (0.68)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.37)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (0.88)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
Shale Oil Fracturing Optimization with an Integrated Workflow in Daqing Oilfield, Northeast China
Xiang, Chuangang (Exploration and Development Research Institute of Daqing Oilfield Co. LTD) | Fu, Zhiguo (Exploration and Development Research Institute of Daqing Oilfield Co. LTD) | Zhuang, Xiangqi (Schlumberger) | Gao, Bei (Schlumberger) | Chen, Yingru (Schlumberger)
Abstract In order to improve the production of Gulong shale oil from well stimulation, a Geoengineering integrated model was established through integration of geological modeling, geomechanics modeling, fracturing modeling and reservoir simulation from QH working pad in Daqing oilfield, Northeast China. Based on integrated modeling workflow and study, key stimulation parameters such as stage interval, clusters of stage, frac liquid volume and proppant volume, well spacing were quantitatively optimized. Optimization study indicated 70-80m stage interval, 10m cluster interval (7 clusters per stage), frac volume 1,400 m per stage, proppant volume 140 m per stage are best parameters in QH pad and 400 m well spacing staggering across zones are best well pattern to QH pad. The study results are of great significance to the realization of large-scale rapid production increase and profitable development for Gulong shale oil reservoirs.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.89)
- Geophysics > Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (0.94)
- Asia > China > Xinjiang Uyghur Autonomous Region > Junggar Basin (0.99)
- Asia > China > Sichuan > Sichuan Basin (0.99)
- Asia > China > Shanxi > Ordos Basin (0.99)
- (5 more...)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- (2 more...)
Abstract The study is based on multi well analysist drilled side by side in carbonate reservoir using high-resolution resistivity image. The objective is to define reservoir characterization, facies architecture, heterogeneity, and connectivity between two wells that is ready for reservoir modeling. The methods presented in this paper are using an automatic inversion and advanced algorithm to generate matrix conductivity images and curves, histogram, analyses rock texture heterogeneities, quantify fluid filled vugs density from high resolution borehole images, fast extraction of dips (beds, fractures), delineate planar features crossing deviated borehole over long distances, extract fracture traces and statistics. More than 3,000 picks of boundaries and fractures were found in a 3,300 ft horizontal length. Those divided into 6 different categories (Bed Boundary, Conductive Fracture, Discontinuous Conductive Fracture, Resistive Fracture, Litho-Bound Fracture, and Vugular fracture). Using high-definition imaging-while-drilling service provides supreme logging-while-drilling (LWD) imaging for reservoir description, from structural modeling, sedimentology analysis, image-based porosity determination and thin-bed analysis. The presence of heterogeneity in carbonates poses a challenge for the characterization of such rocks. The identification of textural variations advanced techniques in borehole image analysis have been applied and presented good results that determine secondary porosity and litho-facies, and, moreover, delivered new insight into previously established interpretations of the reservoir. The data comparison and validation to other measurement show a significant relationship to bring the value even beyond. By using an automatic inversion, the geological interpretation can be constantly delivered around the clock with higher consistency with the number of feature variation. It has been demonstrated that with the advanced analysis, microelectrical borehole images can provide quantitative measures of important reservoir parameters. Accuracy and consistency have been greatly improved since the introduction of microelectrical borehole image logging and subsequent automatic interpretation workflows.
- Asia > Middle East (0.46)
- North America > United States (0.28)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (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 > Borehole imaging and wellbore seismic (1.00)
Tight Oil Field Development Challenges, Lessons Learnt and Successful Implementation of Selected Artificial Lift (SRP) Along with Operational & Digital Solutions: ABH Field, Rajasthan, India
Varma, Nakul (Cairn Oil & Gas, Vedanta Ltd) | Negi, Avdesh (Schlumberger) | Kumar, Manish (Cairn Oil & Gas, Vedanta Ltd) | Chauhan, Shailesh (Cairn Oil & Gas, Vedanta Ltd) | Bohra, Avinash (Cairn Oil & Gas, Vedanta Ltd) | Kothiyal, Manish (Cairn Oil & Gas, Vedanta Ltd)
ABSTRACT Aishwariya Barmer Hill (ABH) field area consists of a laminated high porosity (25-35%), low permeability (~1 mD) unit of 50-250 meters thick hydrocarbon bearing payzone. With the success of the first 6 pilot wells, it was decided to extend to the whole field with more than 44 horizontal wells. The horizontal wells are ~2300-2600 mMD long, lateral average length of 1000m and multistage hydraulic fracturing (10-17). These wells face numerous complications due to high gas-oil ratio, sand production, and corrosion tendencies because of high CO2 mole percent concentration (40-60%) in fluid. Further complications include downhole pumps setting at very high deviation (60-65 deg), rod failures-wear in high deviation wells, rod rotation due to deviation and gradual productivity declines due to sand deposition at lower side of downhole completion. Due to low permeability and low mobility fluid nature, it was necessary to find efficient ways to enhance the overall hydrocarbon recovery factor of the field. Several sensitivities were performed, on the number of wells, number of hydraulic fractures, well design, artificial lift options, water, and gas injection. According to the sensitivities results, the best developed scenario envisages high number of multiple frac wells to increase the recovery factor. Based on the detailed evaluation of available artificial lift options, SRP was selected over Jet pumps as the most suitable artificial lift considering the requirement of large drawdowns & operating costs of lifts. The risk of gas issues was mitigated by keeping the tubing-production casing annulus vented and further alleviated by running suitable downhole gas separators. Other problems were analyzed, and multiple attempts of solution implementation were done. This paper addresses an inhouse ways to tackle sand, high gas rate issues, along with rectifications &learning of other problems faced during the last 3 years of field operations, including digitalization projects for visualization of well behavior. This paper also addresses a few remarkable calculated parameters which are - actual production loss calculations whenever well is shut-in (considering wellbore column storage effects), calculated gas free liquid level pump submergence and pump intake pressure from pump load live data. The purpose of this paper is to describe technical & operational challenges along with lessons learnt/solutions implemented in last 3 years.
- North America > United States > Mississippi > Improve Field (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Barmer Hill Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Bhagyam Field > Barmer Hill Formation (0.99)
- (4 more...)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- Well Completion > Completion Selection and Design > Completion equipment (1.00)
- (7 more...)
One of the main used completion techniques in the gas wells Plug and Perf for proppant or acid stimulation, where the flow through frac plugs are commonly installed to provide isolation between the planned stages to be stimulated. Once the stimulation is completed, the well is flowed back where gas is produced thru the internal diameter restriction in those frac plugs, then all plugs are milled to clear any downhole restriction. The objective of this paper is to evaluate the need of milling frac plugs by simulating the behavior of the Production Index affected by downhole restriction in frac plugs considering those are not milled. The proposed evaluation will investigate the real need of milling the flow thru plugs in the well after the frac operations, as the milling operation has a high cost and complexity. The preferred method is to flow the well without milling operation. However, if the effect of the plugs was significant on the productivity of the wells throughout the years, there will be a need to perform milling operation on the wells to ensure full wellbore accessibility. On the other hand, if the effect was not significant on the future production, the flow thru plugs can be left in the well downhole to avoid the milling operation complications. It is worth to note that milling multiple plugs in a well is a very lengthy and extremely expensive operation looking at the CT and Sand Management System (SMS) daily charges as well as the highly nitrogen consumption (Nunez et al. 2021). The analysis in this paper is split in two parts, where initially Well-A is simulated in PROSPER to compare the production performance in a Plug and Perf completed well with plugs installed or milled. Second part of the analysis is to compare 2 offset wells with real-time data: Well-X with flow thru plugs and Well-Y with flow thru plugs being milled. The results of these analysis as well as the operation total cost and complexity will help in identifying most economical way to apply.
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (0.47)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (0.47)
- (2 more...)
Abstract Three horizontal wells were drilled and completed with hydraulic fracturing in an explorational environment based on reservoir characterization from openhole logs. Limited success in establishing gas production rates showed the need for an integrated technical workflow to be applied for the next well, well-A. After good production results were achieved in well-A, the next phase used three more wells to correlate the production performance based on precise well placement. In well-A, openhole sampling was done during drilling of the pilot hole prior to sidetracking the lateral. This was followed by a novel fracturing approach with slickwater hybrid, low-polymer, and CO2 foamed treatments to study the effectiveness of treatments. Post-fracturing diagnostics including a production log and spectral noise log (SNL) were performed to assess production by stage. Three more wells were drilled in the same reservoir, and then a synthetic correlation model was built with resistivity logs to correlate precise lateral landing with the prolific sublayer. Finally, the production performance of all wells was studied based on well placement, fracturing, and the completion approach. The first phase of the study of the three wells allowed characterizing well-A in terms of reservoir interval, wellbore orientation, and fracturing strategy. Layer 1 was used to sidetrack the lateral. The post-fracturing production log and SNL indicated the CO2 foamed treatment was the best approach for well-A. The next three wells in the development phase were drilled in layer 1 with good production but inconsistent results. Because the highest flow rate in well-A was seen from the heel part of the lateral, an ultradeep resistivity-correlation bed boundary model was generated from well-A to characterize structural dip, and precise lateral locations were analyzed for all the wells. The model was also used to describe the most prolific sublayer within the layer 1 reservoir. The results showed a strong production dependence on the lateral landing with respect to the defined prolific sublayer. The number of fractures placed also showed a direct relation with gas rates. Finally, a geosteering simulation model was built to be used to further develop the area and detailed recommendations were documented. The ultradeep azimuthal resistivity tool has the capacity to detect ultradeep resistivity up to 100 ft from the borehole. Simultaneously, it can map ultrathin layers, which is necessary for the laminated reservoirs. The objectives of precise well placement and rendering productive gas wells in the exploration area through a comprehensive workflow was optimized and analyzed over 4 years. This paper presents systematic findings and a robust framework ready for implementation in future developments.
- North America > United States (0.93)
- Asia > Middle East > Saudi Arabia (0.46)
- Asia > Middle East > UAE (0.28)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (1.00)
- Geology > Geological Subdiscipline > Stratigraphy (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Well Drilling > Drilling Operations (1.00)
- Well Completion > Hydraulic Fracturing (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 (1.00)
Optimum Design for Proppant Fracturing to Unlock Oil Potential in a Marginal Low Quality Burgan Sands in the Greater Burgan Field
Al-Zankawi, Omran (Kuwait Oil Company) | Jafaar, Dunya (Kuwait Oil Company) | Al-Kandari, Shaikha (Kuwait Oil Company) | Yaser, Muhammad (Schlumberger) | Prakash, Roshan (Schlumberger)
Abstract In Greater Burgan Field, Burgan formation is the main oil producing reservoir since the start of oil production and with the reservoir mostly depleted, the focus in the asset team is now on the lower quality Upper Burgan (BGSU) sands with substantial remaining oil. In view of this, a multidisciplinary team is formed to evaluate opportunities to stimulate the BGSU reservoir, establish and sustain production from this reservoir to meet the production targets. The objective is to unlock potential in these tight sands especially targeting to revive old wells back which have drained the underlaying BGSM sands and have significant opportunities in the BGSU. The best way to exploit the resource potential of BGSU for its remaining oil is through hydraulic fracturing technology with an emphasis of its implementation via a thorough review of reservoir, well and completion data maximizing wellbore utilization and minimizing CAPEX investment. The review involves screening a batch of wells with low rock quality and low permeability, away from heavy oil zones and above bubble point pressure, with good shale barrier beneath to avoid fracture propagating into the underlying aquifer. In total, about 100 wells are reviewed from across the Greater Burgan Field for this exercise. Latest reservoir pressure and oil saturation maps for the target BGSU reservoir, built in-house by the asset technical team, are being used to identify wells for potential hydraulic fracturing implementation. Upon a review of historical Proppant fracturing jobs that were performed in five wells in 2015-16 in the BGSU sands, it was summarized that there was a substantial increment to the well productivity, in some cases up to four folds. After the review, detailed numerical well modeling of these five wells is performed with and without fracturing showed that well productivity increase by 2 to 3 times for most of the wells. Although the well productivity improved post stimulation, the wells had high drawdown pressures which resulted in early water breakthrough in few wells. An optimum well productivity can be achieved with large proppant volume placement in the reservoir to connect with the sands away from the wellbore. However, with large volumes there is significant risk of frac propagating "out of zone" increasing the risk of early water breakthrough. Presence of a shale barrier above and below the target zone is an important criterion in candidate selection and design the proppant volume to keep the fracture growth within the target zones and not reach to the zones, especially the underlying BGSM formation, having water. With the lessons-learnt from the past fracturing jobs, detailed modeling and simulation of well performance, a refined list of potential hydraulic fracturing candidates can be generated combined with advancements in the fracturing technology which will greatly enhance the success probability of the stimulation with maximizing well productivity. The successful implementation in the candidate wells will lead to unlocking oil reserve in low rock quality reservoir allowing the development of these low permeability sands for the BGSU upper which will help to achieve the aggressive production target of the South & East Kuwait (SEK) asset.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.46)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Wara Formation (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Ratawi Formation (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Greater Burgan Field > Mauddud Formation (0.99)
- (13 more...)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Well performance, inflow performance (1.00)
Modeling Case Study: Optimizing Multicluster Stimulation Uniformity in Horizontal Wells
Kresse, Olga (Schlumberger) | Sinkov, Konstantin (Schlumberger) | Hobbs, Brandon (Schlumberger)
Abstract The performance and completion efficiency of horizontal multistage hydraulically fractured wells stimulated using the plug-and-perf technique are affected by the uniformity of the multiple perforation cluster treatment. Depending on reservoir heterogeneity, perforation design, and pumping schedule, uneven distribution of fluid and proppant among fractures connected to different perforation clusters can be defined by wellbore proppant transport hydrodynamics, fracture propagation mechanics, or a complex interplay of both. A modeling case study exploring strategies to mitigate nonuniformity of cluster stimulation is presented. Approaches to perforation and treatment optimization are chosen based on consideration of reservoir properties and their heterogeneity. A numerical model coupling a recently developed wellbore flow simulator and an advanced fracture simulator enables comprehensive simulations including both realistic fracture and wellbore modeling for complex perforation designs, treatment schedules, and distributions of reservoir inhomogeneities. The wellbore simulator considers proppant transport and settling, fluid rheology, perforation erosion, rate- and concentration-dependent pressure drop, and variable efficiency of proppant transport to perforations. The fracture simulator models fracture growth, fluid flow, proppant transport inside fractures, and interaction between fracture branches due to stress shadow effect. The interaction between hydraulic and pre-existing natural fractures plays a critical role during fracturing treatments in formations with pre-existing discrete fracture network (DFN). The model considers the effect of formation heterogeneity on fracture propagation, arrest of hydraulic fractures, crossing and opening of natural fractures depending on their properties, fluid viscosity, rate, and stress conditions. Several approaches for optimization of proppant distribution are suggested for cases showing nonperfect proppant transport efficiency caused by high proppant grain inertia. Tapered perforation designs enable achieving more even proppant distribution. However, perforation distribution among clusters providing best stimulation uniformity is sensitive to uncertainties in characterization and heterogeneity of reservoir and discrete fracture network properties. A combination of tapered perforation design and the suppression of inertial effects by increasing carrier fluid viscosity is more robust with respect to reservoir properties variation.
- North America > United States > Texas > Permian Basin > Delaware Basin (0.99)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > New Mexico > Permian Basin > Delaware Basin (0.99)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Well Completion > Completion Installation and Operations > Perforating (1.00)
Hydraulic Fracturing Value Boosting Through Operational Innovation and Data Analytics, MDC and Inchi Fields Case Study
Salazar, Franck (Schlumberger) | Vasconez, Nestor Danilo (Schlumberger) | Artola, Pedro (Schlumberger) | Jaramillo, Dorian (ENAP) | Cueva, Diego (ENAP) | Cuenca, Dario (ENAP) | Coronel, Bernardo (ENAP) | Unapanta, Mauricio (ENAP)
Abstract A fracturing campaign in mature fields in Ecuador demonstrated the advantages of hydraulic fracturing to optimize production and maximize the extraction of the remaining reserves. Good design practices were key to the success of the fracturing campaign in MDC and Inchi fields. Initially, a comprehensive process of characterization was carried out to select the candidates for hydraulic fracturing in the Napo U and T formations to perform an initial fracturing campaign, studying among other characteristics, reservoir permeability, skin, pore pressure, remaining oil saturation, porosity, geomechanical properties, and completion integrity. A small group of wells was selected for hydraulic fracturing using the channel fracturing technique. The second phase consisted of optimizing the fracture design by improving the fracture geometry and conductivity, as well as the application proppant flowback control. Improved fracture geometry and proppant flowback prevention were identified as key elements for the success of the fracturing campaign in these mature fields. Fracturing channel technique was implemented to generate higher fracture conductivity in a low reservoir pressure environment by creating a highly conductive fracture that reduce the drawdown pressure during production. Because of successful implementation, the channel fracturing technique became the preferred completion method in the field for wells requiring stimulation. Twenty five hydraulic fracturing treatments were performed from 2018 to 2022, all demonstrating outstanding production results. The implementation of hydraulic fracturing increased the volume of recoverable reserves by 20%. Operationally, the application of channel fracturing allowed performing more aggressive pump schedules without the risk of screenout, achieving fracture conductivities in the order of 90,000 md-ft and skin values of –2 and –3.5. The learning curve and the results obtained in these fields are important sources of information for implementing hydraulic fracturing in mature fields to increase production and reduce risk.
- South America > Ecuador > Orellana > Oriente Basin > Sacha Field (0.99)
- South America > Ecuador > Orellana > Oriente Basin > Block PBH-I > Inchi Field (0.95)
- South America > Ecuador > Oriente Basin > Napo Formation > Napo U Formation (0.94)
- South America > Colombia > T Formation (0.94)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Management > Professionalism, Training, and Education > Communities of practice (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Knowledge management (1.00)
- Information Technology > Data Science (0.40)
- Information Technology > Artificial Intelligence (0.34)