Analyzing the impact of fracture complexity on well performance and wettability alteration in Eagle Ford shale

2018 ◽  
Author(s):  
Jiawei Li ◽  
Wei Yu ◽  
Kan Wu
Keyword(s):  
Wettability Alteration ◽  
Well Performance ◽  
Eagle Ford Shale ◽  
Eagle Ford ◽  
Fracture Complexity ◽  
The Impact

The impact of pressure and fluid property variation on well performance of liquid-rich Eagle Ford shale

2016 ◽  
Vol 33 ◽  
pp. 1056-1068 ◽  
Author(s):  
S. Amin Gherabati ◽  
John Browning ◽  
Frank Male ◽  
Svetlana A. Ikonnikova ◽  
Guinevere McDaid
Keyword(s):  
Well Performance ◽  
Eagle Ford Shale ◽  
Eagle Ford ◽  
Property Variation ◽  
Fluid Property ◽  
The Impact

Regional assessment of the Eagle Ford Group of South Texas, USA: Insights from lithology, pore volume, water saturation, organic richness, and productivity correlations

2016 ◽  
Vol 4 (1) ◽  
pp. SC125-SC150 ◽  
Author(s):  
Ursula Hammes ◽  
Ray Eastwood ◽  
Guin McDaid ◽  
Emilian Vankov ◽  
S. Amin Gherabati ◽  
...  
Keyword(s):  
Organic Matter ◽  
Pore Volume ◽  
Water Saturation ◽  
Production Quality ◽  
South Texas ◽  
Eagle Ford Shale ◽  
Eagle Ford ◽  
The North ◽  
The Impact ◽  
Sweet Spots

A comprehensive regional investigation of the Eagle Ford Shale linking productivity to porosity-thickness (PHIH), lithology ([Formula: see text]), pore volume (PHIT), organic matter (TOC), and water-saturation ([Formula: see text]) variations has not been presented to date. Therefore, isopach maps across the Eagle Ford Shale play west of the San Marcos Arch were constructed using thickness and log-calculated attributes such as TOC, [Formula: see text], [Formula: see text], and porosity to identify sweet spots and spatial distribution of these geologic characteristics that influence productivity in shale plays. The Upper Cretaceous Eagle Ford Shale in South Texas is an organic-rich, calcareous mudrock deposited during a second-order transgression of global sea level on a carbonate-dominated shelf updip from the older Sligo and Edwards (Stuart City) reef margins. Lithology and organic-matter deposition were controlled by fluvial input from the Woodbine delta in the northeast, upwelling along the Cretaceous shelf edge, and volcanic and clastic input from distant Laramide events to the north and west. Local oxygen minimum events along the South Texas margin contributed to the preservation of this organic-rich source rock related to the Cenomanian/Turonian global organic anoxic event (OAE2). Paleogeographic and deep-seated tectonic elements controlled the variations of lithology, amount and distribution of organic matter, and facies that have a profound impact on production quality. Petrophysical modeling was conducted to calculate total organic carbon, water saturation, lithology, and porosity of the Eagle Ford Group. Thickness maps, as well as PHIH maps, show multiple sweet spots across the study area. Components of the database were used as variables in kriging, and multivariate statistical analyses evaluated the impact of these variables on productivity. For example, TOC and clay volume ([Formula: see text]) show an inverse relationship that is related to production. Mapping petrophysical parameters across a play serves as a tool to predict geologic drivers of productivity across the Eagle Ford taking the geologic heterogeneity into account.

Investigation of Production-Induced Stress Changes for Infill-Well Stimulation in Eagle Ford Shale

SPE Journal ◽  
2018 ◽  
Vol 23 (04) ◽  
pp. 1372-1388 ◽  
Author(s):  
Xuyang Guo ◽  
Kan Wu ◽  
John Killough
Keyword(s):  
Horizontal Wells ◽  
Eagle Ford Shale ◽  
Eagle Ford ◽  
Fracture Geometry ◽  
Complex Fracture ◽  
Study Results ◽  
Stress Changes ◽  
Sensitivity Studies ◽  
Stress States ◽  
The Impact

Summary Heterogeneous stress has a great effect on fracture propagation and perforation-cluster efficiency of infill wells. Principal-stress reorientation induced by depletion of parent wells has been investigated by previous numerical studies assuming uniform biwing fracture geometry along the horizontal wells. However, recent field diagnostics indicate that fractures along the horizontal wells are generally nonuniformly developed. In this study, we investigated the impact of depletion of parent wells with complex fracture geometry on stress states, and analyzed stimulation efficiency of infill wells by using an in-house reservoir geomechanical model for Eagle Ford Shale. The model fully couples multiphase flow and rock deformation in three dimensions based on the finite-element method, incorporating complex fracture geometry and heterogeneity. We used this model to accurately characterize pressure distribution and to update stress states through history matching production data of parent wells in Eagle Ford Shale. Depletion of parent wells with nonuniform fracture geometries, which has not been researched thoroughly in the literature, is incorporated in the study. Results show that magnitude and orientation of principal stresses are greatly altered by depletion, and the alteration is uneven because of nonuniform fracture geometries. Stress reversal monitored at the center of the infill location starts after 1 year of production, and it takes another 8 months to be totally reversed for 90°. We also performed sensitivity studies to examine effects of parameters on changes of magnitude and orientation of stress at the infill location, and found that effects of bottomhole pressure (BHP), differential stress (DS), and fracture geometry of parent wells are all significant, whereas effects of the reservoir elastic property are limited. Effects of production time of parent wells are also noticeable in all sensitivity studies. This work analyzes stress-state change induced by depletion of parent wells in Eagle Ford Shale, and provides critical insights into the optimization for stimulation of infill wells.

Understanding the Impact of Channel Fracturing in the Eagle Ford Shale Through Reservoir Simulation

2012 ◽  
Author(s):  
Raphael Mark Altman ◽  
Anup Viswanathan ◽  
Jian Xu ◽  
Dmitri Ussoltsev ◽  
Shirley Indriati ◽  
...  
Keyword(s):  
Reservoir Simulation ◽  
Eagle Ford Shale ◽  
Eagle Ford ◽  
The Impact

Refracturing on Horizontal Wells in the Eagle Ford Shale in South Texas - One Operator's Perspective

2015 ◽  
Author(s):  
Mamadou Diakhate ◽  
Ayman Gazawi ◽  
Bob Barree ◽  
Manuel Cossio ◽  
Beau Tinnin ◽  
...  
Keyword(s):  
Three Dimensional ◽  
Horizontal Wells ◽  
Well Performance ◽  
Eagle Ford Shale ◽  
Eagle Ford ◽  
Fracture Geometry ◽  
Testing Program ◽  
Pilot Testing ◽  
Fracture Gradient ◽  
Lateral Length

Abstract This paper outlines a refrac pilot testing program conducted in the Eagle Ford Shale. As wells in the Eagle Ford accumulate production over time and the pressure around the horizontal wellbore declines, it is important to also consider communication due to offset fracture stimulation. Refracturing trials in older fields, such as the Barnett Shale have yielded a positive enhancement of well performance (Siebrits et al., 2000). This paper evaluates the concept of diverting fluid and proppant along horizontal wells in the Eagle Ford, while considering any communication with older producing wells during refracturing operations. Pumping data acquired during the refracturing is used to explain some of these concepts. Modeling of induced fracture geometry, considering the effect of current pore pressures, is conducted with a fully three-dimensional hydraulic fracture numerical simulator. The pressure of the subject zone may affect the containment and rate of growth of the new fractures, as well as the re-orientation of the existing fractures. Refracturing an old horizontal well with 5,000 ft lateral length and more than 800 existing perforation holes in the casing is very challenging and requires a careful integration of reservoir knowledge, completions skills and experience. The technical team at Pioneer Natural Resources has developed an integrated workflow to design and execute a refracturing job for an Eagle Ford well. The work flow includes: 1) identification of the lower pressure areas along the lateral using surveillance data from the well, such as microseismic, tracer logs, and production data. 2) identifying which wells within the drilling schedule are offsetting older wells that have high cumulative production, and 3) designing a single fracturing job with several sub-stages separated by diverting agents. Each sub-stage is intended to target specific areas along the lateral, which were previously identified as low pressure zones. Volumes and pump schedules will be specific for each candidate and are based on but not limited to proximity to an offset well, lateral length, and existence of geological structures such as faults and fractures in the area. The results from this pilot testing program such as the radioactive tracers and the fracture gradient changes before and after refrac will be evaluated upon completion of the field execution.

The Third Dimension: Productivity Effects From Spatial Placement and Well Architecture in Eagle Ford Shale Horizontal Wells

2015 ◽  
Author(s):  
William Holcomb ◽  
Randy F. LaFollette ◽  
Ming Zhong
Keyword(s):  
Statistical Significance ◽  
Well Performance ◽  
Eagle Ford Shale ◽  
Multivariate Statistical ◽  
Eagle Ford ◽  
Hydrocarbon Production ◽  
Small Areas ◽  
The Third ◽  
Performance Drivers ◽  
Third Dimension

Abstract Eagle Ford shale formation exhibits highly variability hydrocarbon production rates and EUR within small areas, indicating a highly heterogeneous reservoir. Attempts to determine performance drivers among geological, production or completion data points have produced inconclusive results. For example, production for one cluster of nearby wells may be strongly correlated with proppant quantity, while the trend is not valid for a group of similar wells a short distance away. A more widely valid set of correlations could improve engineering efficiency and productivity across the play. Multivariate statistical modeling has indicated that wellbore architecture factors influence well performance. Such models have determined relative influence of such factors as fracturing fluid type and volumes, proppant sizes and volumes, etc. On the wellbore architecture side, prior studies found that surface latitude and longitude are among the strongest drivers. However, these studies largely omitted consideration of the third dimension (relative vertical location in the reservoir). This study evaluates productivity influences from azimuth, dip, porpoising, and TVD from heel to toe (vertical zone coverage). It also reconsiders previously studied factors (such as fracturing fluids and proppants) with a considerably larger body of data—especially longer-term production data—than was available for the prior studies. The goal is to determine geological, wellbore architecture, and completion factors that show statistical significance as performance drivers, and where they are applicable if the results vary across the play.

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