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Results
Development of fracture diagnostic methods for fluid distribution based on quantitative interpretation of distributed acoustic sensing and distributed temperature sensing
Sakaida, Shohei (Chevron Corporation) | Hamanaka, Yasuyuki (Texas A&M University) | Zhu, Ding (Texas A&M University) | Hill, A. D. (Texas A&M University)
Abstract Multistage hydraulic fracturing design on horizontal wells has significantly evolved with larger fluid volume, more fracturing stages, and tighter perforation cluster spacing to efficiently stimulate unconventional reservoirs. From the published field observations, the recent fracturing design results in complex fracture networks or swarm of fractures. Fracture treatment evaluation is extremely challenging in such a case because of the large amount of variables in well completion and stimulation design. Combined measurements from different technologies can help in fracture diagnosis. Fluid distribution, either during fracture injection or during production, directly relates to the stimulation efficiency at the cluster level and at the stage level. Because it is unlikely in the real world to distribute the injected fluid uniformly among all the clusters, we need diagnostic techniques to generate the flow profile along a lateral. Fiber-optic measurements, such as distributed acoustic sensing (DAS) and distributed temperature sensing (DTS), are currently used to diagnose downhole flow conditions. This technology allows us to qualitatively confirm the fluid flow profile and other issues occurring downhole during fracturing such as leakage through plugs. For optimizing a fracturing design, we also need to understand how the design parameters are correlated with the stimulation efficiency. In this study, we combine two sets of models of DAS and DTS data interpretation for injected fluid volume distribution. The DAS is interpreted based on an empirical correlation between fluid flow rates and frequency band energy from the acoustic signals. The DTS is interpreted by performing temperature history match-based thermal energy conservation. Because of the completely different physics behind the interpretations, the confirmation of two interpretations provides confidence in fluid distribution.
- 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 > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- (32 more...)
Development of fracture diagnostic methods for fluid distribution based on quantitative interpretation of distributed acoustic sensing and distributed temperature sensing
Sakaida, Shohei (Chevron Corporation) | Hamanaka, Yasuyuki (Texas A&M University) | Zhu, Ding (Texas A&M University) | Hill, A. D. (Texas A&M University)
Abstract Multistage hydraulic fracturing design on horizontal wells has significantly evolved with larger fluid volume, more fracturing stages, and tighter perforation cluster spacing to efficiently stimulate unconventional reservoirs. From the published field observations, the recent fracturing design results in complex fracture networks or swarm of fractures. Fracture treatment evaluation is extremely challenging in such a case because of the large amount of variables in well completion and stimulation design. Combined measurements from different technologies can help in fracture diagnosis. Fluid distribution, either during fracture injection or during production, directly relates to the stimulation efficiency at the cluster level and at the stage level. Because it is unlikely in the real world to distribute the injected fluid uniformly among all the clusters, we need diagnostic techniques to generate the flow profile along a lateral. Fiber-optic measurements, such as distributed acoustic sensing (DAS) and distributed temperature sensing (DTS), are currently used to diagnose downhole flow conditions. This technology allows us to qualitatively confirm the fluid flow profile and other issues occurring downhole during fracturing such as leakage through plugs. For optimizing a fracturing design, we also need to understand how the design parameters are correlated with the stimulation efficiency. In this study, we combine two sets of models of DAS and DTS data interpretation for injected fluid volume distribution. The DAS is interpreted based on an empirical correlation between fluid flow rates and frequency band energy from the acoustic signals. The DTS is interpreted by performing temperature history match-based thermal energy conservation. Because of the completely different physics behind the interpretations, the confirmation of two interpretations provides confidence in fluid distribution.
- 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 > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- (32 more...)
Experimental Study on Indoor Multi-Cluster Fracturing Based on Distributed Fibre-Optical Monitoring
Wang, Su (China University of Petroleum (Beijing)) | Chen, Mian (China University of Petroleum (Beijing)) | Chang, Zhi (CNPC Engineering Technology R&D Company Limited) | Zhang, Qixing (China University of Petroleum (Beijing)) | Lv, Jiaxin (China University of Petroleum (Beijing)) | Cui, Zhuang (China University of Petroleum (Beijing)) | Hou, Bing (China University of Petroleum (Beijing) at Karamay)
Abstract Hydraulic fracturing is an important stimulation technique for unconventional oil and gas fields, and real-time monitoring of fractures technology is crucial to evaluate the result of reservoir stimulation. This paper combines distributed sensing equipment based on OFDR with large-scale true triaxial fracturing physical simulation equipment. Then, the laboratory single-cluster and multiple-cluster hydraulic fracturing physical simulation experiments were carried out, while conducted real-time fracture monitoring using bare optical fibre. The experimental results indicate that the location and sequence of fractures initiation can be determined based on the strain evolution of the optical fibre. The general law of fracture propagation on fibre strain evolution can be obtained in single-cluster hydraulic fracturing experiments. In addition to determine the sequence and location of fractures initiation, multi-cluster experiments can also observe the mutual influence of different fractures, and the amount of liquid entering each fractures. These laboratory hydraulic fracturing experiments by distributed optical fibre sensing were conducted under true triaxial conditions, which can provide reference and guidance for on-site oilfield fracturing design.
- Asia > China (0.50)
- North America > United States > Texas (0.28)
- Asia > Middle East > Saudi Arabia (0.28)
- Research Report > New Finding (0.50)
- Research Report > Experimental Study (0.50)
- North America > United States > Texas > Permian Basin > Delaware Basin (0.99)
- North America > United States > New Mexico > Permian Basin > Delaware Basin (0.99)
- Well Completion > Hydraulic Fracturing (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- Well Completion > Completion Monitoring Systems/Intelligent Wells > Downhole sensors & control equipment (0.69)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (0.68)
Validation of a Completion Digital Twin Applied to Packer Setting
Oliveira, L. A. (Engineering Simulation and Scientific Software, Rio de Janeiro, RJ, Brazil) | da Silva, F. R. G. (Engineering Simulation and Scientific Software, Rio de Janeiro, RJ, Brazil) | Bellumat, E. (Engineering Simulation and Scientific Software, Rio de Janeiro, RJ, Brazil) | Gama, W. C. (Petrobras, Rio de Janeiro, RJ, Brazil) | Costa, M. V. F. (Petrobras, Rio de Janeiro, RJ, Brazil) | Donatti, C. N. (Engineering Simulation and Scientific Software, Rio de Janeiro, RJ, Brazil) | Rosenbach, L. I. N. C. (Engineering Simulation and Scientific Software, Rio de Janeiro, RJ, Brazil) | Fasolin, K. (Engineering Simulation and Scientific Software, Rio de Janeiro, RJ, Brazil) | Martins, A. L. (Petrobras, Rio de Janeiro, RJ, Brazil)
Abstract Open hole packers setting usually is performed running in hole the completion equipment and afterwards running a wireline operation to precisely check the packer position and make the needed adjustments to set it in accordance with the geological targets. The current digital twin software incorporates comprehensive models and it receives surface data in real time to analyze the current operation status, by comparing real and calculated (expected) data, with quantitative criteria. It allows the user to follow up the completion column running in hole, to make real time editions if any item needs to be replaced during operation (impact damage, measurement update, etc.). Torque and drag models allow to infer the completion column elongation and verify the real elements position within the well and based on integrity assessment the work window is calculated real time. The target depths are defined during drilling operations using logging data, then drill string elongation calculated with the drilling digital twin software was used to align the real reference depth in both scenarios, drilling and completion. With the real position of the packer in hole it was possible to define the stick up needed to adjust its position to the target depth before setting it. A validation was performed using three offshore real cases, where the packer position considering completion column elongation and the wireline results for packer position considering the pipe tag position detection were compared. In both approaches, a measurement for stick up was obtained to define the correct depth for packer setting and considered to be in good agreement. The novelty is the usage of numerical simulation to optimize the time spent to conclude the packer setting by avoiding an extra operation at the rig site, saving time, costs and operational risks.
- South America > Brazil (0.71)
- North America > United States > Texas (0.69)
- North America > United States > Texas > Permian Basin > Delaware Basin (0.99)
- North America > United States > New Mexico > Permian Basin > Delaware Basin (0.99)
Causal Inference for the Characterization of Microseismic Events Induced by Hydraulic Fracturing
Conde, Oliver Rojas (Harold Vance Department of Petroleum Engineering, Texas A&M University, College Station, Texas, U.S.A.) | Misra, Siddharth (Harold Vance Department of Petroleum Engineering, Texas A&M University, College Station, Texas, U.S.A.) | Liu, Rui (Department of Geology and Geophysics, Texas A&M University, College Station, Texas, U.S.A.)
Abstract This study proposes a workflow that employs causal inference techniques on microseismic data acquired during hydraulic fracturing operations on 2 horizonal wells in Marcellus Shale. The study quantifies the causal relationships between a new microseismic event and the prior "spatiotemporally proximal" microseismic events, while taking into account the confounders that influence both the causes and effects. In doing so, we explain the magnitude, location, and occurrence of a new microseismic event produced during hydraulic fracturing as a consequence of the prior "spatiotemporally proximal" microseismic events. The causal relations quantified in this study are beyond statistical correlation/association tests. The study provides new insights into the microseismic-source mechanisms, such as: 1) Magnitude of a new microseismic event does not depend on the number and the spatial and temporal concentrations of the spatiotemporally proximal, prior microseismic events; 2) Regions with high microseismic magnitude events produce a new microseismic event earlier in time; and 3) Microseismically active regions produce a new microseismic event much earlier in time. Selection of true confounders is crucial for obtaining accurate causal estimates. Failure to properly select confounders can result in significant overestimation or underestimation of the causal estimates, as high as +/- 100%. Certain treatment-outcome pair exhibit large differences between the causal estimates and correlation coefficients that confirm the independence of causation and correlation. A causal analysis with true confounders reveals the true causal relationship that cannot be quantified using correlation/association methods.
- North America > United States > Texas (0.48)
- North America > United States > West Virginia (0.34)
- North America > United States > Virginia (0.34)
- Research Report > Experimental Study (1.00)
- Research Report > Strength High (0.94)
- Research Report > New Finding (0.67)
- Geology > Geological Subdiscipline (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.35)
- 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 > Texas > Permian Basin > Delaware Basin (0.99)
- (5 more...)
Abstract PVT fluid systems vary across the Delaware Basin in Texas, transitioning from black oil in eastern Loving County to volatile oil in the center of northern Loving County, shifting to near-critical fluid or rich gas condensate on the western part of Reeves County. Understanding the GOR behavior of a near-critical fluid system is important for meaningful reserves estimation, optimal well spacing, and efficient completion design. GOR behavior is controlled by PVT fluid system, the initial reservoir conditions, rock-fluid properties, the effective SRV (Stimulated Rock Volume) achieved by hydraulic fracturing, the flow regimes in the dual matrix-fracture system, inter-well communications, and well drawdown strategy. The system pressure and flow regimes developed in the Trilinear system (Brown et al. 2011) of inner fracture plane, outer fracture network, and surrounding tight matrix control the GOR profile shape. The producing GOR of Wolfcamp formations in the Delaware Basin typically exhibits a long GOR transient plateau, which is controlled by the PVT fluid system, the degree of undersaturation, the Linear Flow Parameter (LFP), fracture network complexity, and the contacted OOIP in the SRV. In this study, numerical multiphase RTA modeling was performed for Wolfcamp wells in the near-critical PVT regions. GOR remains constant during the linear transient flow regime; late-time gradual rise in GOR is controlled by LFP/OOIP ratios, which are determined by history matching the linear flow to the boundary-dominated flow curve. The long-term production forecast was accomplished using an integrated EOS (Equation of State) compositional model. The forecast captured GOR behaviors for section-level infill development, which demonstrated long period of constant GOR followed by a gradual rise in GOR. The EOS model was characterized to represent the near-critical fluid system and was tuned using the regional PVT control points. The simulation model was upscaled from the regional subsurface geomodel with facies-controlled petrophysical properties. By incorporating the HFTS II project learnings (Bessa et al. 2021), a GOHFER fracture model was built based on standard completion designs, from which the representative SRV profiles were extracted. The key rock-fluid properties, SRV and completion efficiency, and well spacing configurations were investigated through the history matching process and sensitivity analysis. The integrated analytical and numerical modeling workflow captures the generalized GOR profiles for the Wolfcamp formation in Delaware Basin for three PVT regions: Volatile Oil, Near-Critical Fluid, and Rich Gas Condensate. It also provides a systematic approach for GOR profile construction for given PVT fluid system. Late -time rising GOR in Delaware Basin do not adversely affect the oil EUR as approximately half of the oil recovery was still achieved during rising GOR period. High pressure gradient and high degree of under-saturation is one of the main reasons for long period of constant GOR followed by gentle climb at late-time, which also provides solution gas support for oil recovery. Finally, a regional performance coefficient was proposed for ranking field development based on the PVT fluid system, the degree of under-saturation, and the completion efficiency.
- Geology > Geological Subdiscipline (0.95)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.48)
- 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)
- (23 more...)
Abstract Gas lift is the preferred method of artificial lift of many operators in the Delaware Basin due to high gas/oil ratio's (GOR). The volumes of produced gas have a high liquid yield creating challenges for gas lift compression and surface facilities. Condensate and water drop-out creates pressure fluctuations, out-of-range conditions, and mechanical failures with compression if not effectively managed. Problems occur when liquid slug-flow or carry-over in the gas stream enters the compressor, leading to low suction pressures, out-of-range compressor discharge pressures, or inter-stage pressure fluctuations. In the Delaware Basin, the smaller compressors, typically used for gas lift, are not optimized to handle these liquid-rich gas conditions. This study presents methodologies to improve equipment designs and operating conditions for gas lift as well as predicting more accurately the fluid conditions of the rich Delaware Basin gas. Run time data has been tracked over multiple years for gas lift compressors used by an operator in West Texas. Key findings show that 53% of shutdowns were caused by process upsets and gas conditions. Shutdowns occurred from liquid drop-out that triggered alarms designed to protect the equipment, or that caused direct mechanical failures of valves, compressor cylinders, and scrubber level controls. In all cases, production was suspended, and every restart of the gas lift compressor required a blowdown, creating lost production, operational intervention, and release of carbon emissions. Gas lift compression is set up for single well or multiple well injection utilizing one compressor. Smaller gas lift compressor packages (less than 250 hp) are typically not engineered specifically for the liquid-rich gas. Insufficiently sized suction scrubbers, pocketed piping arrangements, high BTU gas received from flash gas separator/heater treater, and/or lack of adequate temperature control likely contributed to problems of liquid fall-out carrying over into compressors. In the sample well study, gas and liquid samples were collected to conduct process simulation to predict liquid fall-out in the gas lift system design. The results of this work show that the Delaware Basin requires compressor packages and surface facilities specifically engineered for a unique gas composition. The fluid analysis and its findings aided the compressor provider to redesign the compressor system to keep hydrocarbon liquids in solution during all stages of compression allowing gas lift operations in the Delaware Basin to operate more efficiently with fewer mechanical issues. The new technology derived from this work provided a more effective way to reduce liquids dropping out from the gas stream and improve automation with fewer shutdowns and manned interventions. Overall, better control of gas lift operations was maintained, fugitive methane releases were reduced, and gas production was improved while keeping liquids in the gas stream during compression using a Hot Gas Bypass (HGBP) technique.
- 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)
- (24 more...)
Real-Time Drilling Fluid Measurements Provide Value Via Data-Driven Decision Making for Cost-Sensitive Unconventional Environments
Petty, W. (AES Drilling Fluids, Houston, Texas, U.S.A.) | Offenbacher, M. (AES Drilling Fluids, Houston, Texas, U.S.A.) | Jara, R. (ExxonMobil Upstream Research Company, Houston, Texas, U.S.A.) | Rabb, C. (ExxonMobil Upstream Research Company, Houston, Texas, U.S.A.) | Unrau, S. (Pason Systems Corporation, Calgary, Alberta, Canada)
A new approach to real-time automated drilling fluid measurement systems leads to enhanced collaboration and decision making between field and remote operations personnel. The approach is based on straight forward technology that can easily be understood by all, operated by field personnel, and robust enough for fast paced unconventional operations. The sensor information offers real-time actionable data without the demand to replicate the traditional daily mud report, streamlining wellsite activities for drilling fluid treatment as fluid conditions change. The automated drilling fluid measurement system (mud skid) was designed for reliability and simplicity. The idea is to use trending data over the single data point mud check to drive real time decision making across teams.
- Asia (0.69)
- North America > United States > Texas > Harris County > Houston (0.15)
- 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)
- (23 more...)
Interpretation of Rayleigh Frequency Shift Based Distributed Strain Sensing Data During Production and Shut-In of Unconventional Reservoirs
Ou, Yuhao (The University of Texas at Austin, Austin, TX, USA) | Hu, Jinchuan (The University of Texas at Austin, Austin, TX, USA) | Zheng, Shuang (Aramco, Houston, TX, USA) | Sharma, Mukul (The University of Texas at Austin, Austin, TX, USA)
Abstract A new fiber optic measurement, Distributed Strain Sensing based on Rayleigh Frequency Shift, (DSS-RFS) was recently applied to wells in unconventional reservoirs. During production operations, strain changes are measured with high spatial resolution and sensitivity. The objective of this paper is to show that it is possible and very useful to simulate and interpret these strain change plots to identify locations of producing perforation clusters and gain new insights into near wellbore fracture geometry. DSS-RFS fiber optic data is modeled during production from an unconventional reservoir. A fully coupled geomechanical fracture-reservoir simulator is used to simulate full lifecycle of hydraulic fractured horizontal wells, which incorporates the creation of hydraulic fractures with proppant injection, post-frac closure, primary production, cycles of production, shut-in and reopening. An implicit contact force model is implemented for modeling proppant embedment regarding fracture width change during fracture closure and pressure depletion. DSS-RFS plots are generated by obtaining the strain change along the wellbore during production. The simulations are then used to interpret the measurements in terms of pore pressure depletion and near wellbore fracture geometry. The simulated results match well with DSS-RFS data measured in the field. The tensional strain change signals correspond to the locations of active clusters, and the effect of pressure depletion is consistently seen in the simulations. This allows us to quantitatively interpret the measured DSS strain change in terms of the extent of pore pressure depletion during production. The strain change is also found to be related to near wellbore fracture geometry: (1) peak values of the tensional signals are positively correlated with near wellbore fracture width; (2) a larger simulated reservoir volume around a fracture leads to a wider positive strain change signal; (3) the height of the transition zone between active clusters is strongly related to reservoir depletion with respect to both space and time; (4) the height of the extensional signals can be used to assess production allocation among clusters when proppant injection distribution is relatively uniform during fracturing; (5) the shape the extensional signal becomes non-symmetric when there is a large depletion contrast on two sides of a fracture. A series of parameter sensitivity simulation results are analyzed to provide a systematic algorithm for accessing cluster efficiency and production allocation based on DSS-RFS data. The paper presents, a quantitative analysis for assessing cluster efficiency, location of active and inactive clusters and the extent of pore pressure depletion in a horizontal well using DSS-RFS strain change data. In addition, information about near wellbore fracture geometry can be inferred. This is made possible by a new and unique modeling capability that models the entire lifecycle of crack propagation with realistic fracture width and proppant volume distribution (considering stress shadow effects) as well as fluid production and well shut-in.
- Geophysics > Seismic Surveying (0.46)
- Geophysics > Borehole Geophysics (0.46)
- North America > United States > Texas > Permian Basin > Delaware Basin (0.99)
- North America > United States > New Mexico > Permian Basin > Delaware Basin (0.99)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
Surface-Controlled Digital Intelligent Gas Lift Valve Technology Deployed in North American Unconventional Producing Wells. Lessons Learned After Field Trials and the Path Ahead
Suarez, S. A. (Silverwell Technologies Inc, Houston, TX, USA) | Shaw, J. (Silverwell Technologies Inc, Houston, TX, USA) | Bastardo, R. (Silverwell Technologies Inc, Houston, TX, USA) | Patterson, G. (Silverwell Technologies Inc, Houston, TX, USA)
Abstract Objectives/Scope Several wells have now recently been completed with a novel digital intelligent surface-controlled gas lift technology with the goal of assessing their performance and their feasibility as an artificial lift solution for producing unconventional wells. These installs mark the first ever successful installations of this technology in North America land. As of recent years, gas lift has started to gain ground as the artificial lift option of choice for the operators in many Unconventional basins and the goal of this research aims to provide the complete details of the lessons learned during these projects and lay the ground for scaling-up in the near future. Methods, Procedures, Process The research followed closely actual field trial installations of Surface-controlled intelligent gas lift systems that were installed in the Bakken and Permian Basins with the premise of testing its performance prior to larger deployments. The totality of the field trials featured multiple digital intelligent gas lift mandrels that carry pressure and temperature gauges and electrical-actuated valves controlled from surface through a tubing encapsulated line. This can ensure that the optimum gas injection rate can be selected to achieve the maximum production throughout the life of the well over time as Bottom Hole Pressure declines, without the need for wireline intervention to change out a valve, which is required with conventional gas lift. Tailored well designs applications were done to each well candidate with the purpose to evaluate their behavior and agreed-upon KPI's during the trial period. A project closing document was produced for each well which details all the learnings the team was able to gather from real life testing and experience. Results, Observations, Conclusions In these applications, the surface-controlled intelligent gas lift system presents an opportunity for a data driven approach to ensure the optimum gas injection rate is achieved through surface operation and downhole multi-port functionality. While paving the way to other areas where the concept could prove useful as well. We present field unloading procedures, optimization options and well performance enhancements with the newly available data that was able to be gathered. Operational and design improvements were successfully implemented by the team and the operator from the documented lessons. Novel/Additive Information First wells successfully installed in the Unconventional plays in the US, proving that the technology can become a nice fit in the operator's toolbox when dealing with rapid changing conditions and steep declines in production rates coupled with higher Gas Liquid Ratios such as unconventional reservoirs.
- North America > United States > Texas > Permian Basin > Midland Basin (0.99)
- North America > United States > Texas > Permian Basin > Delaware Basin (0.99)
- North America > United States > South Dakota > Williston Basin > Bakken Shale Formation (0.99)
- (27 more...)