|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
Desroches, Jean (Rocks Expert) | Peyret, Emilie (Schlumberger) | Gisolf, Adriaan (Schlumberger) | Wilcox, Ailsa (Schlumberger) | Di Giovanni, Mauro (Schlumberger) | de Jong, Aernout Schram (Schlumberger) | Sepehri, Siavash | Garrard, Rodney (Nagra) | Giger, Silvio (Nagra)
Abstract As part of the Sectoral Plan for Deep Geological Repositories, three candidate sites are currently examined by a focused geological exploration program in Northeastern Switzerland. The program involves 3D seismic surveys and drilling of at least two deep boreholes at each site. Stress testing is being undertaken with a wireline formation testing tool in each borehole (around 20 stress tests per borehole). Improvements in the toolstring were introduced step by step to sharpen the range of the stress estimates and enable 100% coverage of the desired lithological column. This is the first time that a single toolstring with three packers has been run to perform the complete combination of sleeve fracturing, hydraulic fracturing and sleeve reopening tests. A dedicated stress testing protocol was developed to ensure the most robust estimate of the stress in a large variety of formations. A detailed planning process has been developed to maximize the success rate and coverage of stress test stations, integrating all available information as it becomes available. A review of the techniques enabled by the new toolstring for estimating the closure stress from a stress test, especially in low-permeability formations, is presented, and detailed stress testing examples are provided. Preliminary comparison between the stress estimates for the first two boreholes in the campaign are shown.
Shahri, Mojtaba (Apache Corp.) | Tucker, Andrew (Apache Corp.) | Rice, Craig (Apache Corp.) | Lathrop, Zach (Apache Corp.) | Ratcliff, Dave (ResFrac) | McClure, Mark (ResFrac) | Fowler, Garrett (ResFrac)
Abstract In the last decade, we have observed major advancements in different modeling techniques for hydraulic fracturing propagation. Direct monitoring techniques such as fibre-optics can be used to calibrate these models and significantly enhance our understanding of subsurface processes. In this study, we present field monitoring observations indicating consistently oriented, planar fractures in an offset-well at different landing zones in the Permian basin. Frac hit counts, location, and timing statistics can be compiled from the data using offset wells at different distances and depths. The statistics can be used to calibrate a detailed three-dimensional fully coupled hydraulic fracturing and reservoir simulator. In addition to these high-level observations, detailed fibre signatures such as strain response during frac arrival to the monitoring well, post shut-in frac propagation and frac speed degradation with length can be modeled using the simulator for further calibration purposes. Application to frac modeling calibration is presented through different case studies. The simulator was used to directly generate the ‘waterfall plot’ output from the fibre-optic under a variety of scenarios. The history match to the large, detailed synthetic fibre dataset provided exceptional model calibration, enabling a detailed description of the fracture geometry, and a high-confidence estimation of key model parameters. The detailed synthetic fibre data generated by the simulator were remarkably consistent with the actual data. This indicates a good consistency with classical analytical fracture mechanics predictions and further confirm the interpretation of planar fracture propagation. This study shows how careful integration of offset-well fibre-optic measurements can provide detailed characterization of fracture geometry, growth rate, and physics. The result is a detailed picture of hydraulic fracture propagation in the Midland Basin. The comparison of the waterfall plot simulations and data indicate that hydraulic fractures can, in fact, be very well modeled as nearly-linear cracks (the ‘planar fracture modeling’ approach).
Yang, Ruiyue (China University of Petroleum) | Hong, Chunyang (China University of Petroleum) | Huang, Zhongwei (China University of Petroleum) | Wen, Haitao (China University of Petroleum) | Li, Xiaojiang (Sinopec Research Institute of Petroleum Engineering) | Huang, Pengpeng (China University of Petroleum) | Liu, Wei (China University of Petroleum) | Chen, Jianxiang (China University of Petroleum)
Summary Multistage hydraulic fracturing is widely used in developing tight reservoirs. However, the economic and environmental burden of freshwater souring, transportation, treatment, and disposal in hydraulic fracturing operations has been a topic of great importance to the energy industry and public alike. Waterless fracturing is one possible method of solving these water‐related issues. Liquid nitrogen (LN2) is considered a promising alternate fracturing fluid that can create fractures by coupled hydraulic/thermal loadings and, more importantly, pose no threats to the environment. However, there are few laboratory experiments that use LN2 directly as a fracturing fluid. In this work, we examine the performance of LN2 fracturing based on a newly developed cryogenic‐fracturing system under true‐triaxial loadings. The breakdown pressure and fracture morphologies are compared with water fracturing. Moreover, fracture‐initiation behavior under cryogenic in‐situ conditions revealed by cryo‐scanning electron microscopy (cryo‐SEM) is presented, and the role of thermal stress is quantified by a coupled thermoporoelastic‐damage numerical simulation. Finally, the potential application considerations of LN2 fracturing in the field site are discussed. The results demonstrate that LN2 fracturing can lower fracture initiation and propagation pressure and generate higher conductive fractures with numerous thermally induced cracks in the vicinity of the wellbore. Thermal gradient could generate enormously high‐tensile hoop stress and bring about extensive rock damage. Fracture‐propagation direction is inclined to be influenced by the thermal stress. Furthermore, phase transition during the fracturing process and low fluid viscosity of LN2 can also facilitate the fracture propagation and network generation. The key findings obtained in this work are expected to provide a viable alternative for the sustainable development of tight‐reservoir resources in an efficient and environmentally acceptable way.
Summary We propose a novel method for estimating average fracture compressibility during flowback process and apply it to flowback data from 10 multifractured horizontal wells completed in Woodford (WF) and Meramec (MM) formations. We conduct complementary diagnostic flow-regime analyses and calculate by combining a flowing-material-balance (FMB) equation with pressure-normalized-rate (PNR)-decline analysis. Flowback data of these wells show up to 2 weeks of single-phase water production followed by hydrocarbon breakthrough. Plots of water-rate-normalized pressure and its derivative show pronounced unit slopes, suggesting boundary-dominated flow (BDF) of water in fractures during single-phase flow. Water PNR decline curves follow a harmonic trend during single-phase- and multiphase-flow periods. Ultimate water production from the forecasted harmonic trend gives an estimate of initial fracture volume. The estimates for these wells are verified by comparing them with the ones from the Aguilera (1999) type curves for natural fractures and experimental data. The results show that our estimates (4 to 22×10psi) are close to the lower limit of the values estimated by previous studies, which can be explained by the presence of proppants in hydraulic fractures.
Aftab, Muhammad (ADNOC Onshore) | Talib, Noor (ADNOC Onshore) | Subaihi, Maad (ADNOC Onshore) | Lazreq, Nabila (ADNOC) | Nechakh, Abderaouf (Halliburton Energy Services OK) | Leguizamon, Javier (Halliburton Energy Services OK) | Dunlop, Tyson (Halliburton Energy Services OK)
Successful completion and performance of a horizontal well is one of the most dynamic and complex tasks within the oilfield industry, especially when conventional well is an underperformer.
Sustaining production from tight reservoirs with conventional stimulation techniques is one of the most challenging tasks. The reservoir of interest is a tight, low permeable carbonate with thin layers. Productivity proven insignificant with considerable in place volume. The objective is to increase and sustain productivity of a pilot well that consists of an open-hole completion.
Multi-disciplinary data is reviewed in a systematic way to identify reasons of low productivity and to identify possible solutions. After comprehensive studies and risk assessments, it is concluded to re-complete well with cemented Frac string to perform hydraulic fracturing with Plug and Perf (PnP) technique. This technique is applied within a conventional tight reservoir, allowing for the flexibility of stage count, stage spacing, and multi-cluster design in order to maximize the stimulated reservoir volume (SRV) along 2,000 ft. in upper layer, 1,000 ft. across middle layers and 2,000 ft. in lower layer. In addition, company and service provider collaborated to enhance this design through a zero over-flush technique along with diverting agents.
Core, logging data collected from pilot hole is used to build 1D Mechanical Earth Model (MEM), which is further calibrated with MiniFrac performed with Wireline Formation Tester (WFT).
A challenge is to avoid Frac height growth towards underlying reservoir, which is separated by dense carbonate layer of 40 ft.
Extensive modeling is conducted in order to choose correct Frac design along the lateral in which landing depth is variable in different target layers of interest that added complexities to Frac Fluid selection. Finally, two Frac systems are selected for different segments of the lateral. After running a cemented casing, Six (06) Acid fracturing treatment and five (05) Proppant fracturing treatments are successfully executed in the lower and upper layers respectively.
A comprehensive production test is performed to evaluate and compare the testing results of pre and post frac well. To evaluate the contribution of each stage, a Production Logging Tool (PLT) is deployed. The PLT tool shows the contribution and flow distribution across all the clusters and the efficiency of the Frac design and diversion technique/system.
This paper summarizes the design processes, selection criteria, challenges, and lessons learned during design and execution phases. It may provide a potential approach for selecting the proper hydraulic fracturing (Acid Vs Prop) and technique (PnP with clusters Vs PnP with one set of perforation). Company has significant portfolio of undeveloped tight carbonate reservoirs with low productivity and considerable volume in place. This technique will pave the way for developing these reservoirs.
Ibrahim, Ahmed Farid (Shear Frac Group LLC) | Ibrahim, Mazher (Shear Frac Group LLC) | Sinkey, Matt (Shear Frac Group LLC) | Johnston, Thomas (Shear Frac Group LLC) | Johnson, Wes (Shear Frac Group LLC)
The most common stimulation technique for shale production is multistage hydraulic fracturing. Estimating fracture geometry is a focal parameter to judge the fracture operation and predict the well performance. Different direct and indirect techniques can be used for fracture diagnostics to estimates fracture geometries. The current study combines fracture measurements and pressure transient analysis to estimate fracture surface area on each stage and to estimate production as a pseudo production log.
The numbers and kinds of fractures were calculated as a function of treating pressures, injection rates, proppant concentrations, and formation properties to compute fracture surface area (FSA). Pressure transient analyses were then conducted with the leak-off data upon completion of each frac stage to estimate the producing surface (PSA). The fall-off data was processed first to remove the noise and water hammering effects. The PTA diagnostic plots were used to define the flow regime and the data were matched with an analytical model to calculate producing surface area.
Tensile and shear fractures are both created during the injection of frac fluids. Shear fractures are caused by movement in already existing natural (fluid expulsion) fractures found in all shale source rocks. Shear fractures form a pressure below the minimum horizontal stress. These shear fractures take advantage of the rock fabric and develop higher surface area than tensile fractures for the same given volumes of water and sand.
FSA is a measure of permeability enhanced area due to hydraulic fracturing. Producing surface area is the resulting effective flow areaconnected to the wellbore. Diagnostic plots showed a linear and radial flow regime depending on the formation and the completion design. Good correlations were found between PSA and FSA results. In general, higher FSA produces higher PSA. In cases where producing surface area was higher than expected from fracture surface area, communication was found with offset wells. When FSA higher than PSA were found, it was usually caused by increased stress from too close offset wells.
Combining FSA and PSA measurements provides forecasts of production for each stage and helps to optimize well spacing at the end of each frac stage.
Abstract Aimed at sharing the unconventional wisdom gained from a hydraulic fracturing monitoring case study in the Montney tight gas play, the work showcases the ability of 4D modeling of collective behaviors of microseismic events to chase the frac fluid and navigate the spatiotemporal fracture evolution. Moreover, microseismicity-derived deformation fields are integrated with volumetric estimates made by rate transient analysis to calibrate spatially-constrained SRV models. Through the case study, we give evidence of fracture containment, evaluate the role of natural fractures and the use of diverting agents, estimate cluster efficiencies, conduct analytical well spacing optimization, model productivity decline induced by communication frac-hits from offsets, and provide contributing fracture dimensions and numerical production forecasts. To support the interpretations, we supplement the work by the results of 3D physics-based analytical modeling and multi-phase numerical simulations, and the findings are then validated using two extensive datasets: production profiles acquired by fiber optic DAS, and reservoir fluid fingerprints extracted from mud logs. Besides describing the evolution of seismicity during the treatment, the applied integrated fracture mapping process gives a more reliable and unique SRV structure that streamlines forward modeling and simulations in unconventional reservoirs as well as contributes to solving inverse problems more mechanistically.
This paper was prepared for presentation at the Unconventional Resources Technology Conference held in Austin, Texas, USA, 20-22 July 2020. The URTeC Technical Program Committee accepted this presentation on the basis of information contained in an abstract submitted by the author(s). The contents of this paper have not been reviewed by URTeC and URTeC does not warrant the accuracy, reliability, or timeliness of any information herein. All information is the responsibility of, and, is subject to corrections by the author(s). Any person or entity that relies on any information obtained from this paper does so at their own risk. The information herein does not necessarily reflect any position of URTeC. Any reproduction, distribution, or storage of any part of this paper by anyone other than the author without the written consent of URTeC is prohibited. Abstract The publicly available multi-terabyte dataset of the Marcellus Shale Energy and Environmental Lab (MSEEL) consortium provides a unique opportunity to develop fracture models and analyze the effectiveness of the stimulation of a reservoir on a consistent base. Sonic, microresistivity image and production logs, microseismic data, and raw fiber optic measurements are examples of such data. Abundant core samples supplied demonstrate reservoir complexity and high density of natural fractures. The planar fracture model allows us to compare and contrast multiple stimulation strategies and propose engineered completions that cannot be done solely by data-driven approaches. Conclusions about stage spacing, stimulation design, wellbore placement, and stage isolation are shared. The workflow will be detailed to allow others to use, verify, and critique our findings using the same initial data.
ABSTRACT Wellbore collapse and sanding are normally a completion problem during production. Passive failure during fracturing may cause an unexpected borehole stability and also trigger sanding problems in injection wells when a weaker formation is imposed near a wellbore. Considering the formation damage and a formation pore pressure increase because of injection, different sanding mechanisms may be identified and critical drawdows calculated. In addition, the formation damage triggered during injection and sanding problems after production can occur in any cross section area other than r-θ plane which is normally considered. A much different critical sanding pressure may be obtained, thus unexpected sanding problem may occur if we ignore such a possibility. Stresses induced near a cylindrical well are analyzed in this paper. Only a Mohr-Coulomb type criterion is used for plastic yielding during injection and sanding onset during production. Different benchmark such as passive plastic yielding, hydraulic fracturing, active yielding, onset of sanding and a complete loss of injectivity are identified and critical pressures calculated. A complete loss of the injectivity is defined as a consequence when the cumulative sand volume buries the wellbore to a certain level.. 1. INTRODUCTIONS Sand production has been a serious concern in petroleum engineering during production for completion and production engineers. A creation of perforating tunnels and borehole in the subsurface are a process of stress redistribution leading to stress concentration on the borehole and tunnel walls. Once such a stress concentration exceeds strength at the walls, i.e. when one of a Mohr- Coloumb, modifier Lade, Drucker-Prager's and other sanding criteria are satisfied [Bratli and Risenes, 1981; Morita et al., 1989; Ewy, 2000], solid may be produced and a critical producing pressure or flow rate can be obtained. Extensive studies are performed through lab tests, field invetigations, and theoretically [Papamichos et al., 2000; Wang and Wu, 2001, Morita et al., 1989; Ong et al., 2000; Ramaos et al., 1999, Ewy, 1999]. Attempting to understand the mechanisms of the solid production from the formation around a wellbore, most researchers focus on predicting onset or sand rate and defining criteria for the solid production. Although these sanding criteria may not be restricted for producing wells, most of these previous studies are related to the sanding problems in producing wells. Sand probelms in injectors have also been observed in the field [Morita et al., 1998, Santarelli et al. 2000, Esaan et al., 2007, Wang et al 2019]. Such a sanding problem is often blamed to water hammers, cross-flow between layers with different permeabilities, capillary pressure or formation cohesion changes due to water breakthrough, and some possible chemical effects[Santarelli et al. 2000]. On top of these possible mechanisms we suggest three additional processes and mechanisms may also be very likely to occur which should be considered, studied , established as a guideline for completion strategy. In addition to those previous studies for sand production in an injector, a few notes for sand production in the injector can be made based on our preliminary studies: