MACRO-PORE HYDROCARBON SATURATION FROM NMR T1 - T2 MAPS IN THE UNCONVENTIONAL POINT-PLEASANT FORMATION

2021 ◽  
Author(s):  
Xinglin Wang ◽  
◽  
Philip M. Singer ◽  
Zeliang Chen ◽  
Yunke Liu ◽  
...  
Keyword(s):  
Horizontal Well ◽  
Reservoir Characterization ◽  
Total Porosity ◽  
Well Placement ◽  
Shale Formation ◽  
Hydrocarbon Saturation ◽  
Water Saturated ◽  
Organic Shale ◽  
Hydrocarbon Reserves ◽  
Sweet Spots

Of particular interest in unconventional reservoir characterization is an NMR log of total porosity and macro-pore hydrocarbon saturation, where both quantities are independent of a mineralogy model. A log of the macro-pore hydrocarbon saturation has a direct impact on calculating hydrocarbon reserves. It helps identify sweet spots in the reservoir to optimize horizontal-well placement for hydraulic fracturing and production. It also helps avoid water production which would negatively affect the economics of the well. However, NMR logs in unconventional shale are challenging due to potential overlapping signal in the 1-dimensional (1-D) 𝑇𝑇2 domain between micropore water and bound hydrocarbon (i.e. bitumen), and, macro-pore water and hydrocarbons. In response to this challenge, NMR core-analysis in unconventional organic-shale has proven that 2-dimensional (2-D) 𝑇𝑇1 − 𝑇𝑇2 correlation maps and the 𝑇𝑇1/𝑇𝑇2 ratio can be a powerful technique for fluid typing and saturation. One limitation is that these techniques often just compare fully hydrocarbon-saturated with fully brine-saturated cores to calibrate a set of cutoffs in 𝑇𝑇1, 𝑇𝑇2, and/or 𝑇𝑇1/𝑇𝑇2 ratio. These cutoffs are then blindly applied to 𝑇𝑇1 − 𝑇𝑇2 maps from logs or cores of unknown saturation to determine the macro-pore hydrocarbon saturation in the unconventional organic shale. An example from the unconventional Point-Pleasant formation is shown where the traditional 𝑇𝑇1 − 𝑇𝑇2 cutoff technique to determine macro-pore hydrocarbon saturation breaks down, which is remedied by measuring 𝑇𝑇1 − 𝑇𝑇2 maps on mixed hydrocarbon-water saturated cores. The results show that instead of using cutoffs, the log-mean 𝑇𝑇1 , log-mean 𝑇𝑇2 , and log-mean 𝑇𝑇1/𝑇𝑇2 ratio correlate strongly against macro-pore hydrocarbon saturation of the mixed-saturated cores. In particular, for the Point-Pleasant organic-shale formation, the log-mean 𝑇𝑇1 is much more sensitive to macro-pore hydrocarbon saturation than the log-mean 𝑇𝑇2 or log-mean 𝑇𝑇1/𝑇𝑇2 ratio. The calibration of macro-pore hydrocarbon saturation from log-mean 𝑇𝑇1 is found to be different above and below a para-sequence boundary (nonconformity) in the organic-shale interval, the results of which can be used to interpret NMR logs. Details of the time-efficient technique used to obtain the mixed hydrocarbon-water saturated cores are shown.

Brenda Field Development: A Best Practice In Horizontal Well Placement Leading To Optimal Reservoir Drainage

2007 ◽  
Author(s):  
Ken E.T. Halward ◽  
Joe Emery ◽  
Rod Christensen ◽  
Daniel Joseph Bourgeois ◽  
Grant Skinner ◽  
...  
Keyword(s):  
Best Practice ◽  
Horizontal Well ◽  
Well Placement ◽  
Field Development

A Novel Workflow for Geosteering a Horizontal Well in a Low Resistivity Contrast Anisotropic Environment: A Case Study in Semoga Field, Indonesia

2021 ◽  
Author(s):  
Yessica Fransisca ◽  
Karinka Adiandra ◽  
Vinda Manurung ◽  
Laila Warkhaida ◽  
M. Aidil Arham ◽  
...  
Keyword(s):  
Real Time ◽  
Horizontal Well ◽  
Gamma Ray ◽  
Lessons Learned ◽  
Electrical Anisotropy ◽  
Anisotropy Ratio ◽  
Well Placement ◽  
Low Contrast ◽  
Low Resistivity ◽  
The Subject

Abstract This paper describes the combination of strategies deployed to optimize horizontal well placement in a 40 ft thick isotropic sand with very low resistivity contrast compared to an underlying anisotropic shale in Semoga field. These strategies were developed due to previously unsuccessful attempts to drill a horizontal well with multiple side-tracks that was finally drilled and completed as a high-inclined well. To maximize reservoir contact of the subject horizontal well, a new methodology on well placement was developed by applying lessons learned, taking into account the additional challenges within this well. The first approach was to conduct a thorough analysis on the previous inclined well to evaluate each formation layer’s anisotropy ratio to be used in an effective geosteering model that could better simulate the real time environment. Correct selections of geosteering tools based on comprehensive pre-well modelling was considered to ensure on-target landing section to facilitate an effective lateral section. A comprehensive geosteering pre-well model was constructed to guide real-time operations. In the subject horizontal well, landing strategy was analysed in four stages of anisotropy ratio. The lateral section strategy focused on how to cater for the expected fault and maintain the trajectory to maximize reservoir exposure. Execution of the geosteering operations resulted in 100% reservoir contact. By monitoring the behaviour of shale anisotropy ratio from resistivity measurements and gamma ray at-bit data while drilling, the subject well was precisely landed at 11.5 ft TVD below the top of target sand. In the lateral section, wellbore trajectory intersected two faults exhibiting greater associated throw compared to the seismic estimate. Resistivity geo-signal and azimuthal resistivity responses were used to maintain the wellbore attitude inside the target reservoir. In this case history well with a low resistivity contrast environment, this methodology successfully enabled efficient operations to land the well precisely at the target with minimum borehole tortuosity. This was achieved by reducing geological uncertainty due to anomalous resistivity data responding to shale electrical anisotropy. Recognition of these electromagnetic resistivity values also played an important role in identifying the overlain anisotropic shale layer, hence avoiding reservoir exit. This workflow also helped in benchmarking future horizontal well placement operations in Semoga Field. Technical Categories: Geosteering and Well Placement, Reservoir Engineering, Low resistivity Low Contrast Reservoir Evaluation, Real-Time Operations, Case Studies

Advanced Multi-Disciplinary Simulation Workflow for Well Placement, Hydraulic Fracturing and Production Optimization Applied to the Diyab Unconventional Play in Onshore UAE

2021 ◽  
Author(s):  
Hamid Pourpak ◽  
Samuel Taubert ◽  
Marios Theodorakopoulos ◽  
Arnaud Lefebvre-Prudencio ◽  
Chay Pointer ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
United Arab Emirates ◽  
Reservoir Characterization ◽  
Horizontal Wells ◽  
Production Optimization ◽  
Production Performance ◽  
Well Placement ◽  
Fully Integrated ◽  
Sector Model ◽  
The Impact

Abstract The Diyab play is an emerging unconventional play in the Middle East. Up to date, reservoir characterization assessments have proved adequate productivity of the play in the United Arab Emirates (UAE). In this paper, an advanced simulation and modeling workflow is presented, which was applied on selected wells located on an appraisal area, by integrating geological, geomechanical, and hydraulic fracturing data. Results will be used to optimize future well landing points, well spacing and completion designs, allowing to enhance the Stimulated Rock Volume (SRV) and its consequent production. A 3D static model was built, by propagating across the appraisal area, all subsurface static properties from core-calibrated petrophysical and geomechanical logs which originate from vertical pilot wells. In addition, a Discrete Fracture Network (DFN) derived from numerous image logs was imported in the model. Afterwards, completion data from one multi-stage hydraulically fracked horizontal well was integrated into the sector model. Simulations of hydraulic fracturing were performed and the sector model was calibrated to the real hydraulic fracturing data. Different scenarios for the fracture height were tested considering uncertainties related to the fracture barriers. This has allowed for a better understanding of the fracture propagation and SRV creation in the reservoir at the main target. In the last step, production resulting from the SRV was simulated and calibrated to the field data. In the end, the calibrated parameters were applied to the newly drilled nearby horizontal wells in the same area, while they were hydraulically fractured with different completion designs and the simulated SRVs of the new wells were then compared with the one calculated on the previous well. Applying a fully-integrated geology, geomechanics, completion and production workflow has helped us to understand the impact of geology, natural fractures, rock mechanical properties and stress regimes in the SRV geometry for the unconventional Diyab play. This work also highlights the importance of data acquisition, reservoir characterization and of SRV simulation calibration processes. This fully integrated workflow will allow for an optimized completion strategy, well landing and spacing for the future horizontal wells. A fully multi-disciplinary simulation workflow was applied to the Diyab unconventional play in onshore UAE. This workflow illustrated the most important parameters impacting the SRV creation and production in the Diyab formation for he studied area. Multiple simulation scenarios and calibration runs showed how sensitive the SRV can be to different parameters and how well placement and fracture jobs can be possibly improved to enhance the SRV creation and ultimately the production performance.

Utilizing NMR Workflow to Optimize Power Water Injector Placement in the Presence of Tar Barriers

2021 ◽  
Author(s):  
Gabor Hursan ◽  
Mohammed Sahhaf ◽  
Wala’a Amairi
Keyword(s):  
Spectral Analysis ◽  
Pore Size ◽  
Real Time ◽  
Total Porosity ◽  
Carbonate Reservoir ◽  
Wettability Alteration ◽  
Well Placement ◽  
Carbonate Formation ◽  
Fluid Saturation ◽  
Rock Quality

Abstract The objective of this work is to optimize the placement of horizontal power water injector (PWI) wells in stratified heterogeneous carbonate reservoir with tar barriers. The key to successful reservoir navigation is a reliable real-time petrophysical analysis that resolves rock quality variations and differentiates tar barriers from lighter hydrocarbon intervals. An integrated workflow has been generated based on logging-while drilling (LWD) triple combo and Nuclear Magnetic Resonance (NMR) logging data for fluid identification, tar characterization and permeability prediction. The workflow has three steps; it starts with the determination of total porosity using density and neutron logs, the calculation of water-filled porosity from resistivity measurements and an additional partitioning of porosity into bound and free fluid volumes using the NMR data. Second, the total and water-filled porosity, the NMR bound fluid and NMR total porosity are used as inputs in a hydrocarbon compositional and viscosity analysis of hydrocarbon-bearing zones for the recognition of tar-bearing and lighter hydrocarbon intervals. Third, in the lighter hydrocarbon intervals, NMR logs are further analyzed using a multi-cutoff spectral analysis to identify microporous and macroporous zones and to calculate the NMR mobility index. The ideal geosteering targets are highly macroporous rocks containing no heavy hydrocarbons. In horizontal wells, the method is validated using formation pressure while drilling (FPWD) measurements. The procedure has been utilized in several wells. The original well path of the first injector was planned to maintain a safe distance above an anticipated tar-bearing zone. Utilizing the new real-time viscosity evaluation, the well was steered closer to the tar zone several feet below the original plan, setting an improved well placement protocol for subsequent injectors. In the water- or lighter hydrocarbon-bearing zones, spectral analysis of NMR logs clearly accentuated micro- and macroporous carbonate intervals. The correlation between pore size and rock quality has been corroborated by FPWD mobility measurements. In one well, an extremely slow NMR relaxation may indicate wettability alteration in a macroporous interval. An integrated real-time evaluation of porosity, fluid saturation, hydrocarbon viscosity and pore size has enhanced well placement in a heterogeneous carbonate formation where tar barriers are also present. The approach increased well performance and substantially improved reservoir understanding.

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