Diagnostic Plots of Pressure Transient, Rate-Transient, and Diagnostic Fracture-Injection/Falloff Tests

2021 ◽  
Author(s):  
David Craig ◽  
Thomas Blasingame
Keyword(s):  
Flow Regimes ◽  
Horizontal Stress ◽  
Test Theory ◽  
Pressure Transient ◽  
Diagnostic Plots ◽  
Diagnostic Plot ◽  
New Ideas ◽  
Characteristic Features ◽  
Pressure Transient Test ◽  
Minimum Horizontal Stress

Abstract All transient test interpretation methods rely on or utilize diagnostic plots for the identification of wellbore or fracture storage distortion, flow regimes, and other parameters (e.g., minimum horizontal stress). Although all "test" interpretations of interest are transient test data (i.e., those involving an "event"), the associated diagnostic plots are not interchangeable between such tests. The objective of this work is to clearly define the appropriate diagnostic plot(s) for each type of transient test. The work applies the appropriate transient test theory to demonstrate the applicability of each diagnostic plot along with clearly defining the characteristic features that make a given plot "diagnostic." For pressure transient testing, the material is largely a review, but for rate transient tests and diagnostic fracture-injection/falloff tests, new ideas are introduced and documented to justify appropriate diagnostic plots. Data examples are provided for illustration and application. In general, pressure transient test diagnostic plots are not misused, but the same cannot be said for diagnostic fracture-injection/falloff tests (or DFITs) where it is common to ascribe flow regimes and/or draw other erroneous conclusions based on observations from an inappropriately constructed or interpretated diagnostic plot. The examples provided illustrate both the correct diagnostic plot and interpretations, but also illustrate how data can be easily misinterpreted in common practice.

Pressure-Transient Tests and Flow Regimes in Fractured Reservoirs

2015 ◽  
Vol 18 (02) ◽  
pp. 187-204 ◽  
Author(s):  
Fikri Kuchuk ◽  
Denis Biryukov
Keyword(s):  
History Matching ◽  
Fractured Reservoirs ◽  
Flow Regimes ◽  
Naturally Fractured Reservoirs ◽  
Dual Porosity ◽  
Hydraulic Fractures ◽  
Fractured Reservoir ◽  
Pressure Transient ◽  
Matrix Block ◽  
Naturally Fractured

Summary Fractures are common features in many well-known reservoirs. Naturally fractured reservoirs include fractured igneous, metamorphic, and sedimentary rocks (matrix). Faults in many naturally fractured carbonate reservoirs often have high-permeability zones, and are connected to numerous fractures that have varying conductivities. Furthermore, in many naturally fractured reservoirs, faults and fractures can be discrete (rather than connected-network dual-porosity systems). In this paper, we investigate the pressure-transient behavior of continuously and discretely naturally fractured reservoirs with semianalytical solutions. These fractured reservoirs can contain periodically or arbitrarily distributed finite- and/or infinite-conductivity fractures with different lengths and orientations. Unlike the single-derivative shape of the Warren and Root (1963) model, fractured reservoirs exhibit diverse pressure behaviors as well as more than 10 flow regimes. There are seven important factors that dominate the pressure-transient test as well as flow-regime behaviors of fractured reservoirs: (1) fractures intersect the wellbore parallel to its axis, with a dipping angle of 90° (vertical fractures), including hydraulic fractures; (2) fractures intersect the wellbore with dipping angles from 0° to less than 90°; (3) fractures are in the vicinity of the wellbore; (4) fractures have extremely high or low fracture and fault conductivities; (5) fractures have various sizes and distributions; (6) fractures have high and low matrix block permeabilities; and (7) fractures are damaged (skin zone) as a result of drilling and completion operations and fluids. All flow regimes associated with these factors are shown for a number of continuously and discretely fractured reservoirs with different well and fracture configurations. For a few cases, these flow regimes were compared with those from the field data. We performed history matching of the pressure-transient data generated from our discretely and continuously fractured reservoir models with the Warren and Root (1963) dual-porosity-type models, and it is shown that they yield incorrect reservoir parameters.

Geodynamic implications of the Cenozoic stress field on Seymour Island, West Antarctica

2008 ◽  
Vol 20 (2) ◽  
pp. 173-184 ◽  
Author(s):  
A. Maestro ◽  
J. López-Martínez ◽  
F. Bohoyo ◽  
M. Montes ◽  
F. Nozal ◽  
...  
Keyword(s):  
Stress Field ◽  
Antarctic Peninsula ◽  
Horizontal Stress ◽  
Weddell Sea ◽  
Scotia Sea ◽  
Compressional Stress ◽  
The North ◽  
Stress States ◽  
Bransfield Basin ◽  
Minimum Horizontal Stress

AbstractPalaeostress inferred from brittle mesostructures in Seymour (Marambio) Island indicates a Cenozoic to Recent origin for an extensional stress field, with only local compressional stress states. Minimum horizontal stress (σ3) orientations are scattered about two main NE–SW and NW–SE modes suggesting that two stress sources have been responsible for the dominant minimum horizontal stress directions in the north-western Weddell Sea. Extensional structures within a broad-scale compressional stress field can be linked to both the decrease in relative stress magnitudes from active margins to intraplate regions and the rifting processes that occurred in the northern Weddell Sea. Stress states with NW–SE trending σ3are compatible with back-arc extension along the eastern Antarctic Peninsula. We interpret this as due to the opening of the Larsen Basin during upper Cretaceous to Eocene and to the spreading, from Pliocene to present, of the Bransfield Basin (western Antarctic Peninsula), both due to former Phoenix Plate subduction under the Antarctic Plate. NE–SW σ3orientations could be expressions of continental fragmentation of the northern Antarctic Peninsula controlling eastwards drifting of the South Orkney microcontinent and other submerged continental blocks of the southern Scotia Sea.

scholarly journals Rupture Directivity in 3D Inferred From Acoustic Emissions Events in a Mine-Scale Hydraulic Fracturing Experiment

2021 ◽  
Vol 9 ◽  
Author(s):  
José Ángel López-Comino ◽  
Simone Cesca ◽  
Peter Niemz ◽  
Torsten Dahm ◽  
Arno Zang
Keyword(s):  
Hydraulic Fracturing ◽  
Acoustic Emissions ◽  
Local Stress ◽  
Horizontal Stress ◽  
Monitoring Networks ◽  
Rupture Directivity ◽  
Shallow Subsurface ◽  
Minimum Horizontal Stress ◽  
Directivity Effects ◽  
Full Waveforms

Rupture directivity, implying a predominant earthquake rupture propagation direction, is typically inferred upon the identification of 2D azimuthal patterns of seismic observations for weak to large earthquakes using surface-monitoring networks. However, the recent increase of 3D monitoring networks deployed in the shallow subsurface and underground laboratories toward the monitoring of microseismicity allows to extend the directivity analysis to 3D modeling, beyond the usual range of magnitudes. The high-quality full waveforms recorded for the largest, decimeter-scale acoustic emission (AE) events during a meter-scale hydraulic fracturing experiment in granites at ∼410 m depth allow us to resolve the apparent durations observed at each AE sensor to analyze 3D-directivity effects. Unilateral and (asymmetric) bilateral ruptures are then characterized by the introduction of a parameter κ, representing the angle between the directivity vector and the station vector. While the cloud of AE activity indicates the planes of the hydrofractures, the resolved directivity vectors show off-plane orientations, indicating that rupture planes of microfractures on a scale of centimeters have different geometries. Our results reveal a general alignment of the rupture directivity with the orientation of the minimum horizontal stress, implying that not only the slip direction but also the fracture growth produced by the fluid injections is controlled by the local stress conditions.

A Comprehensive Model Integrating the Stress Sensitivity for Pressure Transient Behavior Study on the Two-Zone System for Offshore Loose Sandstone Reservoirs

2021 ◽  
Author(s):  
Chong Cao ◽  
Linsong Cheng ◽  
Xiangyang Zhang ◽  
Pin Jia ◽  
Wenpei Lu
Keyword(s):  
Flow Regimes ◽  
Transient Behavior ◽  
Stress Sensitivity ◽  
Composite Model ◽  
Zone Model ◽  
Well Testing ◽  
Comprehensive Model ◽  
Pressure Transient ◽  
Sandstone Reservoirs ◽  
Sandstone Formation

Abstract Permeability changes in the weakly consolidated sandstone formation, caused by sand migration, has a serious impact on the interpretation of well testing and production prediction. In this article, a two-zone comprehensive model is presented to describe the changes in permeability by integrating the produced sand, stress sensitivity characteristics. In this model, inner zone is modeled as a higher permeability radial reservoir because of the sand migration, while the outer zone is considered as a lower permeability reservoir. Besides, non-Newtonian fluid flow characteristics are considered as threshold pressure gradient in this paper. As a result, this bi-zone comprehensive model is built. The analytical solution to this composite model can be obtained using Laplace transformation, orthogonal transformation, and then the bottomhole pressure in real space can be solved by Stehfest and perturbation inversion techniques. Based on the oilfield cases validated in the oilfield data from the produced sand horizontal well, the flow regimes analysis shows seven flow regimes can be divided in this bi-zone model considering stress sensitive. In addition, the proposed new model is validated by the compassion results of traditional method without the complex factors. Besides, the effect related parameters of stress sensitivity coefficient, skin factor, permeability ratio and sanding radius on the typical curves of well-testing are analyzed. This work introduces two-zone composite model to reflect the variations of permeability caused by the produced sand in the unconsolidated sandstone formation, which can produce great influence on pressure transient behavior. Besides, this paper can also provide a more accurate reference for reservoir engineers in well test interpretation of loose sandstone reservoirs.

A Novel Method and its Application to Define Maximum Horizontal Stress and Stress Path

2021 ◽  
Author(s):  
Jianguo Zhang ◽  
Karthik Mahadev ◽  
Stephen Edwards ◽  
Alan Rodgerson
Keyword(s):  
Fracture Initiation ◽  
Stress Path ◽  
Horizontal Stress ◽  
Geomechanical Model ◽  
Breakdown Pressure ◽  
In Situ Stresses ◽  
Fracture Closure ◽  
Minimum Horizontal Stress ◽  
Maximum Horizontal Stress

Abstract Maximum horizontal stress (SH) and stress path (change of SH and minimum horizontal stress with depletion) are the two most difficult parameters to define for an oilfield geomechanical model. Understanding these in-situ stresses is critical to the success of operations and development, especially when production is underway, and the reservoir depletion begins. This paper introduces a method to define them through the analysis of actual minifrac data. Field examples of applications on minifrac failure analysis and operational pressure prediction are also presented. It is commonly accepted that one of the best methods to determine the minimum horizontal stress (Sh) is the use of pressure fall-off analysis of a minifrac test. Unlike Sh, the magnitude of SH cannot be measured directly. Instead it is back calculated by using fracture initiation pressure (FIP) and Sh derived from minifrac data. After non-depleted Sh and SH are defined, their apparent Poisson's Ratios (APR) are calculated using the Eaton equation. These APRs define Sh and SH in virgin sand to encapsulate all other factors that influence in-situ stresses such as tectonic, thermal, osmotic and poro-elastic effects. These values can then be used to estimate stress path through interpretation of additional minifrac data derived from a depleted sand. A geomechanical model is developed based on APRs and stress paths to predict minifrac operation pressures. Three cases are included to show that the margin of error for FIP and fracture closure pressure (FCP) is less than 2%, fracture breakdown pressure (FBP) less than 4%. Two field cases in deep-water wells in the Gulf of Mexico show that the reduction of SH with depletion is lower than that for Sh.

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.

scholarly journals Brittleness Evaluation in Shale Gas Reservoirs and Its Influence on Fracability

Energies ◽  
2020 ◽  
Vol 13 (2) ◽  
pp. 388 ◽  
Author(s):  
Yapei Ye ◽  
Shuheng Tang ◽  
Zhaodong Xi
Keyword(s):  
Shale Gas ◽  
Evaluation Method ◽  
Triaxial Compression ◽  
Horizontal Stress ◽  
Brittleness Index ◽  
X Ray Diffraction ◽  
Elastic Parameters ◽  
Gas Reservoirs ◽  
Shale Gas Reservoirs ◽  
Minimum Horizontal Stress

The brittleness index (BI) is a key parameter used to identify the desirable fracturing intervals of shale gas reservoirs. Its correlation with fracability is still controversial. There have been a variety of methods proposed that can estimate BI. The brittleness evaluation method based on stress-strain curves according to the energy-balanced law is the most suitable and reliable in this study. Triaxial compression test, optical microscopy and scanning electron microscopy (SEM) observation, and X-ray diffraction analysis (XRD) were performed on nine drill core samples from well SY3 located in the peripheral regions of Sichuan Basin, China. These tests further evaluated several commonly used methods (brittleness indices based on rock elastic parameters, rock mineral compositions) and determined the relationship between brittleness, rock elastic parameters, and the content of minerals. The results obtained indicate that for sedimentary rocks, a higher Young’s modulus reduces the brittleness of rock, and Poisson’s ratio weakly correlates with brittleness. Excessive amounts of quartz or carbonate minerals can increase the cohesiveness of rock, leading to poor brittleness. Furthermore, the most suitable fracturing layers possess a high brittleness index and low minimum horizontal stress.

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