Identification of brittle/ductile areas in unconventional reservoirs using seismic and microseismic data: Application to the Barnett Shale

2015 ◽  
Vol 3 (4) ◽  
pp. T233-T243 ◽  
Author(s):  
Roderick Perez Altamar ◽  
Kurt J. Marfurt
Keyword(s):  
Clay Content ◽  
Elastic Parameter ◽  
Unconventional Reservoirs ◽  
Seismic Survey ◽  
Parameter Estimates ◽  
Hydraulic Fractures ◽  
Seismic Acquisition ◽  
Microseismic Events ◽  
3D Volume ◽  
Horizontal Wellbores

Brittleness in unconventional reservoirs is mainly controlled by mineralogy, and it increases with quartz and dolomite content, whereas an increase in the clay content represents an increase in ductility. To generate regional brittleness maps, we have correlated the mineralogy-based brittleness index to elastic parameters measured from well logs. This correlation can then be used to predict the brittleness from surface seismic elastic parameter estimates of [Formula: see text] and [Formula: see text]. We applied the workflow to a 3D seismic survey acquired in an area where more than 400 wells were drilled and hydraulically fractured prior to seismic acquisition. Combining [Formula: see text] and [Formula: see text] into a single 3D volume allowed the combination of both attributes into a single 3D volume, which can be converted to brittleness using a template based on the well log and core data. Neither of these seismic estimates were direct measures of reservoir completion quality. We, therefore, used production logs and extracted surface seismic estimates at microseismic event locations to analyze the completion effectiveness along several horizontal wellbores in the reservoir. We defined four petrotypes in [Formula: see text] and [Formula: see text] space depending on their brittleness and gas saturation, and we found that most of the microseismic events fell into the zone described as brittle in the [Formula: see text]-[Formula: see text] crossplots. These observations supported the well-known idea that regardless of where the well was perforated, microseismic events appeared to preferentially grow toward the more brittle areas, suggesting the growth of hydraulic fractures into the brittle petrotype.

Efficient Localized Nonlinear Solution Strategies for Unconventional-Reservoir Simulation with Complex Fractures

2021 ◽  
Author(s):  
Jiamin Jiang
Keyword(s):  
Transient Flow ◽  
A Priori ◽  
Time Discretization ◽  
Unconventional Reservoirs ◽  
Hydraulic Fractures ◽  
Nonlinear Solution ◽  
Compositional Model ◽  
Simulation Speed ◽  
Flow Mechanisms ◽  
Solution Accuracy

Abstract It is very challenging to simulate unconventional reservoirs efficiently and accurately. Transient flow can last for a long time and sharp solution (pressure, saturation, compositions) gradients are induced because of the severe permeability contrast between fracture and matrix. Although high-resolution models for well and fracture are required to achieve adequate resolution, they are computationally too demanding for practical field models with many stages of hydraulic fracture. The paper aims to innovate localization strategies that take advantage of locality on timestep and Newton iteration levels. The strategies readily accommodate to complicated flow mechanisms and multiscale fracture networks in unconventional reservoirs. Large simulation speed-up can be obtained if performing localized computations only for the solution regions that will change. We develop an a-priori method to exploit the locality, based on the diffusive character of the Newton updates of pressure. The method makes adequate estimate of the active computational gridblock for the next iterate. The active gridblock set marks the ones need to be solved, and then the solution to local linear system is accordingly computed. Fully Implicit Scheme is used for time discretization. We study several challenging multi-phase and compositional model cases with explicit fractures. The test results demonstrate that significant solution locality of variables exist on timestep and iteration levels. A nonlinear solution update usually has sparsity, and the nonlinear convergence is restricted by a limited fraction of the simulation model. Through aggressive localization, the proposed methods can prevent overly conservative estimate, and thus achieve significant computational speedup. In comparison to a standard Newton method, the novel solver techniques achieve greatly improved solving efficiency. Furthermore, the Newton convergence exhibits no degradation, and there is no impact on the solution accuracy. Previous works in the literature largely relate to the meshing aspect that accommodates to horizontal wells and hydraulic fractures. We instead develop new nonlinear strategies to perform localization. In particular, the adaptive DD method produces proper domain partitions according to the fluid flow and nonlinear updates. This results in an effective strategy that maintains solution accuracy and convergence behavior.

On the reconstruction of the shape of a seismic streamer

Geophysics ◽  
2010 ◽  
Vol 75 (1) ◽  
pp. H1-H6
Author(s):  
Bruno Goutorbe ◽  
Violaine Combier
Keyword(s):  
A Priori ◽  
Synthetic Data ◽  
Seismic Survey ◽  
Random Errors ◽  
Generalized Inversion ◽  
Reconstruction Methods ◽  
Seismic Acquisition ◽  
Marine Seismic ◽  
Gps Devices ◽  
Vessel Reconstruction

In the frame of 3D seismic acquisition, reconstructing the shape of the streamer(s) for each shot is an essential step prior to data processing. Depending on the survey, several kinds of constraints help achieve this purpose: local azimuths given by compasses, absolute positions recorded by global positioning system (GPS) devices, and distances calculated between pairs of acoustic ranging devices. Most reconstruction methods are restricted to work on a particular type of constraint and do not estimate the final uncertainties. The generalized inversion formalism using the least-squares criterion can provide a robust framework to solve such a problem — handling several kinds of constraints together, not requiring an a priori parameterization of the streamer shape, naturally extending to any configuration of streamer(s), and giving rigorous uncertainties. We explicitly derive the equations governing the algorithm corresponding to a marine seismic survey using a single streamer with compasses distributed all along it and GPS devices located on the tail buoy and on the vessel. Reconstruction tests conducted on several synthetic examples show that the algorithm performs well, with a mean error of a few meters in realistic cases. The accuracy logically degrades if higher random errors are added to the synthetic data or if deformations of the streamer occur at a short length scale.

Rock physics of the Wolfcamp Formation, Delaware Basin

Geophysics ◽  
2019 ◽  
Vol 84 (6) ◽  
pp. B353-B361 ◽  
Author(s):  
Colin M. Sayers ◽  
Sagnik Dasgupta ◽  
Adam Koesoemadinata ◽  
Michael Shoemaker
Keyword(s):  
Anisotropy Parameter ◽  
Rock Physics ◽  
Horizontal Stress ◽  
P Wave ◽  
Seismic Survey ◽  
Hydraulic Fractures ◽  
Anisotropic Rock ◽  
Delaware Basin ◽  
Organic Carbon Concentration ◽  
Minimum Horizontal Stress

Production from wells in organic-rich shales often shows considerable lateral variation. Reliable predrill methods to characterize the lateral heterogeneity of such reservoirs are required to optimize the trajectory of lateral wells in these low-permeability reservoirs. Petrophysical interpretation of measured well logs provides information on mineral, porosity, and kerogen content. Combining the results of petrophysical analysis with P-wave, S-wave, and density logs allows generation of a probability density function (PDF) for each of the different significant lithofacies. The PDFs are applied to the P- and S-impedance from prestack seismic amplitude variation with offset inversion to predict the spatial variation in the distribution of lithofacies and associated probability for the Wolfcamp Formation in an area covered by a 3D seismic survey in the Delaware Basin, West Texas. An anisotropic rock-physics model for the Wolfcamp Formation allows the effect of complex mineralogy, organic carbon concentration, and porosity on the P- and S-impedance to be investigated. Kerogen inclusions and pores act to increase Thomsen’s anisotropy parameter [Formula: see text] relative to [Formula: see text], and there is a competition between clay matrix anisotropy and inclusion shape anisotropy in determining the anisotropy of the rock. Inclusions with isotropic elastic properties act to decrease the anisotropy due to the dilution effect, but this decrease is partially offset by the increase in anisotropy due to the anisotropic shape of the inclusions. Application of the model to the determination of minimum horizontal stress indicates that kerogen-rich siliceous shales have the lowest value of minimum horizontal stress, whereas silica-rich calcareous shales, mixed siliceous shales, and clay-rich siliceous shales have higher values and may therefore act as barriers for the vertical growth of hydraulic fractures.

Introduction to this special section: Acquisition and sensing

2019 ◽  
Vol 38 (9) ◽  
pp. 670-670
Author(s):  
Margarita Corzo ◽  
Tim Brice ◽  
Ray Abma
Keyword(s):  
Special Section ◽  
Seismic Survey ◽  
Ocean Bottom ◽  
Total Cost ◽  
Small Boat ◽  
Air Gun ◽  
Seismic Acquisition ◽  
The Cost ◽  
Seismic Images

Seismic acquisition has undergone a revolution over the last few decades. The volume of data acquired has increased exponentially, and the quality of seismic images obtained has improved tremendously. While the total cost of acquiring a seismic survey has increased, the cost per trace has dropped precipitously. Land surveys have evolved from sparse 2D lines acquired with a few dozen receivers to densely sampled 3D multiazimuth surveys. Marine surveys that once may have consisted of a small boat pulling a single cable have evolved to large streamer vessels pulling multiple cables and air-gun arrays and to ocean-bottom detectors that require significant fleets to place the detectors, shoot the sources, and provide support. These surveys collect data that are wide azimuth and typically fairly well sampled.

NEW GAS DISCOVERIES IN THE NORTHERN COOPER BASIN

1996 ◽  
Vol 36 (1) ◽  
pp. 104
Author(s):  
H.R.B. Wecker ◽  
V. Ziolkowski ◽  
G.D. Powis
Keyword(s):  
Seismic Survey ◽  
Gas Flows ◽  
Mount Isa ◽  
Seismic Acquisition ◽  
Reservoir Sandstones ◽  
Well Data ◽  
Gas Potential ◽  
Southeast Queensland ◽  
Cooper Basin

Over the last two decades, minimal gas exploration was undertaken in the northeastern Cooper Basin. It was viewed the area held negligible gas potential due to the perceived absence of conventional anticlinal traps and the marginal reservoir quality of the Permian sandstones.With the award of permit ATP 549P to Mount Isa Mines Limited in mid-1993, available seismic and well data were reviewed to highlight potential fault-controlled traps in the region and to define areas likely to contain more favourable reservoir sandstones. A vibroseis seismic survey provided the initial prospects and leads inventory upon which the 1994 drilling program was based. Four prospects were tested resulting in three gas discoveries.Based on these encouraging results, an additional phase of seismic acquisition was completed to increase the prospect inventory. Thereafter, a five well program was undertaken. Whilst the two appraisal wells were successful, three wildcat wells failed due to ineffective trapping.A completion and testing program has been initiated to further evaluate the field discoveries.From an exploration viewpoint, the recognition of a consistently productive sandstone in the basal Toolachee Formation within a broad fairway across the eastern ATP 549P permit block was a significant result which has important implications for future activities. Within the fairway, gas flows varying from 0.4 MMcfd up to 6.0 MMcfd were measured on openhole tests. In addition, substantial gas volumes in low permeability sandstones within the Patchawarra Formation have been defined.These discoveries, coupled with the number of prospects and leads and the proposed gas pipeline to Mount Isa and to southeast Queensland markets, provide strong impetus to the continued evaluation of this northern extension of the Cooper Basin gas province.

Passive Seismic Marchenko Imaging

2020 ◽  
Author(s):  
Zhongyuan Jin
Keyword(s):  
Free Surface ◽  
Seismic Data ◽  
Low Cost ◽  
Body Waves ◽  
Seismic Survey ◽  
Significant Difference ◽  
Passive Seismic ◽  
Seismic Acquisition ◽  
Imaging Property ◽  
Internal Multiples

<p>In recent years, seismic interferometry (SI) has been widely used in passive seismic data, it allows to retrieve new seismic responses among physical receivers by cross-correlation or multidimensional deconvolution (MDD). Retrieval of reflected body waves from passive seismic data has been proved to be feasible. Marchenko method, as a new technique, retrieves Green’s functions directly inside the medium without any physical receiver there. Marchenko method retrieves precise Green’s functions and the up-going and down-going Green’s functions can be used in target-oriented Marchenko imaging, and internal multiples related artifacts in Marchenko image can be suppressed. </p><p>Conventional Marchenko imaging uses active seismic data, in this abstract, we propose the method of passive seismic Marchenko imaging (PSMI) which retrieves Green’s functions from ambient noise signal. PSMI employs MDD method to obtain the reflection response without free-surface interaction as an input for Marchenko algorithm, such that free-surface multiples in the retrieved shot gathers can be eliminated, besides, internal multiples don’t contribute to final Marchenko image, which means both free-surface multiples and internal multiples have been taken into account. Although the retrieved shot gathers are contaminated by noises, the up-going and down-going Green’s functions can be still retrieved. Results of numerical tests validate PSMI’s feasibility and robustness. PSMI provides a new way to image the subsurface structure, it combines the low-cost property of passive seismic acquisition and target-oriented imaging property of Marchenko imaging, as well as the advantage that there are no artifacts caused by internal multiples and free-surface multiples.</p><p>Overall, the significant difference between PSMI and conventional Marchenko imaging is that passive seismic data is used into Marchenko scheme, which extends the Marchenko imaging to passive seismic field. Passive seismic Marchenko imaging avoids the effects of free-surface multiples and internal multiples in the retrieved shot gathers. PSMI combines the low-cost property of passive seismic acquisition and target-oriented imaging property of Marchenko imaging which is promising in future field seismic survey.</p><p>This work is supported by the Fundamental Research Funds for the Central Universities (JKY201901-03). </p>

Adaptive finite element–discrete element analysis for stratal movement and microseismic behaviours induced by multistage propagation of three-dimensional multiple hydraulic fractures

2021 ◽  
Vol ahead-of-print (ahead-of-print) ◽  
Author(s):  
Yongliang Wang
Keyword(s):  
Finite Element ◽  
Numerical Models ◽  
Three Dimensional ◽  
Fracture Propagation ◽  
Discrete Element ◽  
Hydraulic Fractures ◽  
Adaptive Finite Element ◽  
Fracture Networks ◽  
Content Type ◽  
Microseismic Events

Purpose Optimized three-dimensional (3D) fracture networks are crucial for multistage hydrofracturing. To better understand the mechanisms controlling potential disasters as well as to predict them in 3D multistage hydrofracturing, some governing factors, such as fluid injection-induced stratal movement, compression between multiple hydraulic fractures, fracturing fluid flow, fracturing-induced microseismic damaged and contact slip events, must be properly simulated via numerical models. This study aims to analyze the stratal movement and microseismic behaviours induced by multistage propagation of 3D multiple hydraulic fractures. Design/methodology/approach Adaptive finite element–discrete element method was used to overcome the limitations of conventional finite element methods in simulating 3D fracture propagation. This new approach uses a local remeshing and coarsening strategy to ensure the accuracy of solutions, reliability of fracture propagation path and computational efficiency. Engineering-scale numerical models were proposed that account for the hydro-mechanical coupling and fracturing fluid leak-off, to simulate multistage propagation of 3D multiple hydraulic fractures, by which the evolution of the displacement, porosity and fracture fields, as well as the fracturing-induced microseismic events were computed. Findings Stratal movement and compression between 3D multiple hydraulic fractures intensify with increasing proximity to the propagating fractures. When the perforation cluster spaces are very narrow, alternate fracturing can improve fracturing effects over those achieved via sequential or simultaneous fracturing. Furthermore, the number and magnitude of microseismic events are directly proportional to the stratal movement and compression induced by multistage propagation of fracturing fracture networks. Originality/value Microseismic events induced by multistage propagation of 3D multiple hydraulic fractures and perforation cluster spaces and fracturing scenarios that impact the deformation and compression among fractures in porous rock matrices are well predicted and analyzed.

Comparing P-P, P-SV, and SV-P mode waves in the Midland Basin, West Texas

2016 ◽  
Vol 4 (2) ◽  
pp. T183-T190 ◽  
Author(s):  
Michael V. De Angelo ◽  
Bob A. Hardage
Keyword(s):  
Vertical Component ◽  
P Wave ◽  
Seismic Survey ◽  
Vertical Force ◽  
S Wave ◽  
Converted Wave ◽  
Midland Basin ◽  
West Texas ◽  
Exploration Risk ◽  
Seismic Acquisition

We acquired 3D multicomponent data in Andrews County, Midland Basin, West Texas with a seismic survey. We extracted direct-SV modes generated by a vertical-force source (an array of three inline vertical vibrators) from the vertical component of multicomponent geophones. This seismic mode, SV-P, was created by reprocessing legacy 2D/3D P-wave seismic data to create converted-wave data and consequently forgoing the need for a multicomponent seismic acquisition program to obtain important S-wave information from the subsurface. We have compared P-P, P-SV, and SV-P traveltime and amplitude characteristics to determine which seismic mode provided better characterization of the targeted reservoirs and reduced exploration risk.

Sign in / Sign up

Export Citation Format

Share Document