Sabine Uplift

Abstract

Understanding and modeling the interaction between hydraulic fractures and natural fractures is important to predict shale production performance. This paper presents a workflow that incorporates natural fractures, rock properties, and stress regimes to understand fracture behavior during stimulation treatment. The methodology also integrates the predefined discrete fracture network (DFN) and 3D reservoir properties to build a comprehensive hydraulic fracturing model. Heat maps are also generated to help evaluate completion design and well spacing strategies.

Applying the integrated fracture characterization workflow to the study area revealed that the vertical and lateral fracture growth is a function of structural context, stress conditions, and rock mechanical properties. Stimulation parameters, including proppant volume and injection pressures, for one horizontal and six vertical wells were utilized to build a comprehensive fracture network for the study area. The resulting model shows: (a) the stimulation of predefined natural fractures, and (b) the generation of induced fractures in the maximum stress direction associated with re-activation of pre-existing faults and fractures. The modeling results were validated by interwell interference data.

Introduction

Fractures play an important role in hydrocarbon production from organic-rich shale reservoirs (Gale, et al., 2014). This is evident from the higher than expected production rates typically observed from low-porosity and ultra-low permeability shale rocks. Moreover, many shale outcrops, cores, and image logs show an abundance of natural fractures or fracture traces. This study integrates natural fracture characteristics, directional stresses, and hydraulic fractures to characterize and better comprehend Permian Wolfcamp production performance.

Several factors influence the stimulated rock volume (SRV) geometry during a hydraulic fracturing stimulation treatment. These factors include: structural context, natural fracture networks, rock mechanical properties, lithology, and stress changes associated with tectonic events (Gale et al., 2014; Maity, 2018). Furthermore, natural fracture systems in shales are heterogeneous; they can enhance or reduce formation productivity, augment or diminish rock strength, and may have a tendency to influence hydraulic fracture stimulation (Doe et al., 2013). The flow of stimulation fluid through natural fractures and the generation of hydraulic fractures were modeled in this study.

Abstract

Shear reactivation of pre-existing fractures can play a crucial role in hydraulic stimulation to enable production from unconventional reservoirs. Evidence of the phenomenon is found in microseismic/seismic events induced during stimulation by hydraulic fracturing. However, induced seismicity and permeability evolution in response to fracture shear reactivation by injection has not been extensively studied in laboratory tests under relevant conditions. In this work, a cylindrical Eagle Ford shale sample having a single fracture (tensile fracture) was used to perform laboratory injection test with concurrent acoustic emission (AE) monitoring. In the test, slip was induced on the fracture at near critical stress state by injecting pressurized brine water (7% KCL). Sample deformation (stress, displacement), fluid flow (injection pressure, flow rate) and AE signals (hits, events) were all recorded. The data was then used to characterize the fractures’ fully coupled seismo-hydro-mechanical response during shearing. Results shown that the induced AE/microseismic events correlate well with the fracture slip and the permeability evolution. Most of the recorded AE hits and events were detected during the seismic slip interval corresponding a rapid fracture slip and a quick stress relaxation. As a result of dilatant shear slip, a remarkable enhancement of fracture permeability was achieved. Prior to this seismic interval, an aseismic slip interval was evident during the tests, where the fracture slip, the associated stress relaxation, and the permeability increase were limited. The test results and analyses clearly demonstrate the role of shear slip in permeability enhancement by hydraulic stimulation for unconventional shale reservoirs. Finally, it is further revealed that the transition from aseismic slip to seismic slip is highly dependent on the fracture slip velocity.

Introduction

Shear slip of pre-existing fractures has been recognized as a major permeability creation and micro-seismicity mechanism of reservoir stimulation for a long time (e.g. Pine and Batchelor 1984, Mayerhofer et al. 1997, Rutledge et al. 2004, Zoback et al. 2012). Most reservoir rocks contain abundant pre-existing fractures, some of which may be sealed with calcite or other infill minerals. Usually, these fractures are inactive and without sufficient permeability before stimulation. A number of modeling and field studies have shown that when the pre-existing natural fractures are favorably oriented with respect to the in-situ stresses, an injection or the leak-off from a hydraulic fracture (even with low fluid pressure) can cause the fractures sliding and propping due to asperities. Also, it is widely observed that the induced microseismic or seismic events during hydraulic injection are mostly related to the shear failure of pre-existing fractures. However, fracture slip-permeability evolution and the associated microseismic signature during injection are still poorly understood. The fundamental investigations through laboratory experiments and field injection tests are insufficient.

Summary

In this paper we describe a novel method for water unloading of natural gas wells in mature reservoirs experiencing low reservoir pressures. Current methods for water unloading from gas wells have at least one of the drawbacks of restricting gas production, requiring external energy, using consumable surfactants, or being labor intensive. The proposed design offers a new approach to water unloading that does not restrict or interrupt gas production. It can operate without external energy, and uses no consumables. Virtual and physical simulators have been developed and the full-scale version of the concept has been studied in test wells to demonstrate the feasibility and performance of the new water-unloading concept. An industrial-grade preproduction prototype was tested successfully in a test gas well to validate this study.

Abstract

Over the last several decades, many studies have generated a large amount of proppant performance data, but these studies have only focused on proppant conductivity, with no attention to how proppant mechanical properties vary under loading conditions. The impact of mechanical behaviour on proppant performance can only be fully understood by the combined investigation of micro-structural and mechanical changes with increasing loading. Therefore, this study aims to identify such micro-structural behaviour, and in particular the impact on proppant mechanical properties. Proppant samples were tested under one-dimensional compression loading using high-resolution X-ray CT scanning technology. The reconstructed images taken at different load stages were analysed to capture the micro-structural behaviour and finally correlated with the mechanical behaviour of the proppant.

According to the results, there are significant micro-pore voids inside the proppant mass. When the proppant has a higher degree of porosity, there is a considerable reduction of the compressive strength which is not favourable for hydro-fracturing treatment designs. Moreover, it is clear that the brittleness of the proppant decreases with increasing porosity, as its Young’s modulus reduces with increasing pore voids. Therefore, it is important to have high manufacturing standards to achieve effective proppant performance at great depths. The micro-structural behaviour under increasing loading was investigated by performing comprehensive CT image analysis using Drishti software. According to the results, under compressive loading, proppants cleave and generate large fragments like a flower, and this happens suddenly and quite violently through the material. Interestingly, post-failure analysis revealed that the failure mechanism of a single proppant consists of three major stress levels, where initially proppant fails at a high stress level and gains some crushing-associated strength at later stages.

1. Introduction

Unconventional oil/gas production has recently attracted the research community due to the uncontrollable increasing demand for primary energy sources (Perera et al., 2016; Wu et al., 2017). Since this method provides a good solution to energy scarcity, over the last several decades, the industry has tried to enhance the production rate, mainly focusing on production enhancement techniques which can be effectively used in the energy extraction from sub-surface geological formations. Of the various options, hydraulic fracturing is one of the best ways to enhance oil/gas extraction, as it increases the formation’s permeability, allowing easy movement of the extracted oil/gas towards the production well (Rutledge and Scott, 2003; Orangi et al., 2011; Vengosh et al., 2014; Wanniarachchi et al., 2015). However, this process may be jeopardised due to the high stress levels acting on the formation at great depths (both vertical overburden and confining pressures). One possible consequence is re-closure of the fracture network under downhole stress conditions, which severely affects the post-fracturing production. Such issues can negate the use of proppant as a hydraulic fracture treatment method where proppants injected with the fracturing fluid prop the fractures, withstanding the fracture-closure stress (Wanniarachchi et al., 2015). Although the proppant gives a reliable solution to overcome this issue (propping the fracture network), sufficient closure stress can cause mechanical failure of the proppant, changing the fracture conductivity, causing re-closure of the fracture network, and altering the bulk properties of the proppant pack, which can negatively influence oil/gas extraction. Therefore, it is important to understand the mechanical behaviour of proppants under downhole stress conditions before injecting proppant with the hydro-fracturing fluid.

A detailed microseismic survey was carried out in the Spraberry Field of Midland County, Texas. A vertical pilot well was completed in eight separate stages and was monitored from four surrounding wells within 300 m of the completion well. Each monitor well was equipped with a 20-level 3C geophone array spanning the completion zones. A velocity model was built from dipole sonic and calibrated for vertical transverse isotropy (VTI) parameters using perforation shots, sonic-derived anisotropy, and crosswell seismic time picks. The microseismic locations reveal simple vertical planar clouds only a few meters wide and oriented along maximum horizontal stress direction. Moment tensor solutions show a mix of strike-slip and dipslip shear mechanisms along failure planes aligned with the hydraulic fracture orientation. Formation microimager data indicate that natural fractures play little or no role in generating the microseismicity or guiding fracture growth. The observations indicate that the microseismic shearing is directly associated with the hydraulic fractures.

Presentation Date: Wednesday, October 17, 2018

Start Time: 1:50:00 PM

Location: 208A (Anaheim Convention Center)

Presentation Type: Oral

Currently, there are several (four main) widely discussed theories used to describe how microseismicity interacts with hydraulic fracturing. Each theory has a different implication for the interpretation of microseismicity used for reservoir modeling. Therefore, better understanding of the relationship between microseismicity and hydraulic fracture stimulation is needed before further reservoir models are developed and applied. This would lead to a more precise estimation of stimulated rock volume, hydrocarbon production and give greater value to microseismic data. We may use either seismic or non-seismic methods. While non-seismic methods provide an independent view of hydraulic fracturing they only provide a limited amount of information on the relationship between hydraulic fracturing and microseismicity. We propose microseismic monitoring of directivity as the most promising way to determine the orientation of fault planes and associated slip vectors. Although this is a suitable method it requires sensors in multiple azimuths that are well coupled to obtain reliable high frequency signals. We suggest using Distributed Acoustic Sensing (DAS) sensors which are capable of sampling at high frequency and may provide continuous data along long offsets at reasonable costs.

Presentation Date: Tuesday, October 16, 2018

Start Time: 1:50:00 PM

Location: 208A (Anaheim Convention Center)

Presentation Type: Oral

We present a method for modeling the transient growth of drilling-induced fractures through a porous medium in the near wellbore region. Understanding the early time fracture growth behavior, and related near wellbore stress state, can provide an effective tool to improve the treatment selection through parameters such as particle size distribution and ideal drilling fluid rheology. Also, it will help with field diagnostics for various lost circulation treatments and lost return events.

ExxonMobil Upstream Research Company and SIMULIA® co-developed fully-coupled hydraulic fracturing modeling capabilities. The model was benchmarked with known solutions to analytical fracture growth regimes and validated with a laboratory scale experimental setup of hydraulic fracturing. The model allows for fluid leak-off from the wellbore and fracture faces into the porous medium for an arbitrary injection schedule.

The time-dependent fracture growth and interaction between the stress concentration region near the fracture tip and the wellbore result in a non-linear behavior of the near-wellbore stress state during early time fracture propagation, which was not possible to capture with static models. This analysis allows for recommendation of an optimum fracture width for maximum increase in wellbore integrity in the target formation. This is done by selecting the fracture width at the mouth, at which the desired increase in the near-wellbore tangential stresses has been achieved as to prevent initialization of further fractures. The model was applied to a field scale example and the predicted integrity gain from fracture plugging agrees well with observations.

We investigate a novel application of Frechet derivatives for time-lapse mapping of deep, electrically–enhanced fracture systems with a borehole to surface DC resistivity array. The simulations are evaluated for a cased horizontal wellbore embedded in a homogeneous halfspace, where measurements are evaluated near, mid–range, and far from the well head. We show that, in all cases, measurements are sensitive to perturbations centered on the borehole axis and that the sensitivity volume decreases as a function of increased measurement offset from the well head. The sensitivity analysis also illustrates that careful consideration must be taken when developing an electrical survey design for these scenarios. Specifically, we show that positive perturbations in earth conductivity near the wellbore can manifest as both positive and negative measurement perturbations, depending on where the measurement is taken. Furthermore, we show that the transition between the regions along the wellbore of positive and negative contribution results in a "pinch point", representing a region along the wellbore where a given surface measurement is blind to any changes or enhancement of electrical conductivity.

Presentation Date: Wednesday, October 19, 2016

Start Time: 2:20:00 PM

Location: 174

Presentation Type: ORAL

In this study, we take a preliminary look at microseismic data collected along the length of two Marcellus shale horizontal wells (the 3H and 5H) drilled by Northeast Natural Energy LLC (NNE) in Morgantown, West Virginia. Detailed log data are also available along the length of one of the laterals (the 3H) that provide a wealth of information concerning geomechanical properties, fracture trend and intensity. Logging, processing and interpretation of image logs were provided by Schlumberger. Preliminary interpretation of the microseismic cluster trends reveals orientations on average of about N59°E. Image logs in the vertical pilot well reveal similar average open fracture trend of ~N58°E. The orientation of S_Hmax estimated from induced fractures observed in the vertical pilot well is ~N57°E, while that from breakouts is about N64°E. The majority of the induced fractures are observed in the Marcellus, while the breakouts are largely observed about 2000 feet above the Marcellus. Image logs collected along approximately 7400’ of lateral provide additional insights into the fracture network within the Marcellus target zone. Over 1600 fractures were interpreted by the Schlumberger analyst. The distribution was unimodal with average fracture trend of N78°E. Along the length of the lateral, average trends of fracture clusters varied from about N64°E to N110°E.

S_hmin in the area is approximately 6500 psi with horizontal stress anisotropy varied between 100 to 400psi in agreement with the acoustic scanning platform data. The vertical stress (S_v) is approximately 8800psi. Asymmetry in the microseismicity associated with the well is interpreted to be associated with a drop in S_hmin toward parallel well (the 5H well) located northeast. Hydraulic fracture stimulation of the local fracture network along the 3H well required introduction of a negative horizontal stress gradient in S_hmin northeast towards the 5H well that was treated a few days earlier to produce observed asymmetry in the microseismic distribution. Variation in stage-to-stage shut-in pressures did not suggest significant stress shadowing or increase in S_hmin stage-to-stage toward the heel (see Nagel et al., 2013a and b) or between wells.

In this initial look at the microseismic data, model fracture stimulation patterns are compared to microseismicity from a single stage along the 3H lateral. Initial uncalibrated MEM and stochastic based DFN models suggest that the observed microseismic event trends require interaction of the local N83°E fracture set observed in the image log along the wellbore in this area with a more regional ~N59°E fracture set. Although the inferred N59°E set is not prominent in the image log interpretations in the target landing zone, it is a prominent open fracture set in the vertical pilot well and its presence appears to control microseismic event trends and natural fracture stimulation at the site. This set appears to provide tensile conduits that channel fluids into and facilitate microseismically audible rupture of east-northeast fractures that are observed in the vicinity of the stage and that fail through shear.

Presentation Date: Tuesday, October 18, 2016

Start Time: 1:00:00 PM

Location: Lobby D/C

Presentation Type: POSTER

We treat microseismic events with high signal to noise ratio (SNR) as master events and cross-correlate with continuous recording using both P - and S - waves to detect weak events (slave events). Subsequently, the detected weak events were located relatively to the master events, by stacking together the P - and S - waves cross - correlations along differential moveouts. Specifically, we add the azimuth restriction of P-wave to the cross - correlation stacking to improve the location accuracy in the case of single downhole acquisition. The utility of this technique is demonstrated with synthetic events. Then, we applied our method to real microseismic data from one stage of hydraulic fracturing operation.