This paper was prepared for presentation at the Unconventional Resources Technology Conference held in Houston, Texas, USA, 23-25 July 2018. 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. 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.
Hydraulic fracturing has been the main completion technique to enhance production from unconventional shale reservoirs. Determination of the hydraulic fracture geometry is of great significance to obtain a reliable assessment of the treatment, production prediction, and validation of fracture models. In this study, we investigate the idea of using an electromagnetic induction logging tool to diagnose hydraulic fractures using functionally-graded conductive proppants as contrasting agents to enhance the tool response.
A finite element method is utilized to solve Maxwell’s equations to simulate the impact of different hydraulic fracture geometries on the tool response. To minimize the application of special type of proppant and better estimate fracture length, we propose using a functionally-graded configuration for proppant placement, in which the density of proppant particles can be adjusted by tuning the volume of the inner void space to assure about their placement locations. Hence, fractures are imaged by detecting the distribution of highly conductive particles around fracture edges. The tool consists of a transmitter and a set of receiver coils that measure the time-harmonic electric and magnetic fields as the logger sonde travels along the wellbore. Different transmitter-receiver spacings of induction tools are considered to obtain optimal parameters that can be used for field operations. Results show it is possible to qualitatively use the tool to determine length, and width of hydraulic fractures. Utilization of special placement of conductive particles at the top and bottom fractures gives a stronger relationship of tool responses to hydraulic fracture geometries. Relationships of logging results for different hydraulic fracture geometries, as well as electromagnetic properties, are established. Results also show the tool can identify fractures’ length up to 200 ft long in horizontal wells. A larger transmitter-receiver spacing of 16 m gives a deep reading for fractures with larger length. A smaller transmitter-receiver spacing of 1.2 m enables more accurate determination of the location of hydraulic fractures along the wellbore.
Hydraulic fracturing has become the major completion method for oil and gas production from unconventional shale reservoirs in the United States. Better understanding of the dimension of hydraulic fractures is of great importance in treatment evaluation, production forecasting and validation of fracture models. Currently, there are two major fracture diagnostic method categories; far-field and near-field methods.
Microseismic events and their source mechanisms play a significant role in our understanding of hydraulic fracturing. To better identify the reliability of source mechanisms, we examine the limitations of microseismic field data imposed by (1) lack of angular coverage, (2) moment tensor inversion constraints, and (3) effects of mild anisotropy. We use synthetic seismograms to examine cases of either pure double-couple (DC) or compensated-linear-vector dipole (CLVD) sources. The open-source full-wavefield moment tensor inversion code (ISOLA) incorporates both near- and intermediate-field terms, which can increase the accuracy of the inversion if source-receiver distances are small. The tested locations and dominant source frequencies of the synthetic seismograms used for analysis resemble the expected locations and dominant frequencies of microseismic events extracted from a multi-stage field data set in the Barnett Shale of East Texas. We conclude that although a horizontal receiver array can provide greater angular coverage of vertical failure planes than a vertical receiver array, the strike of shear (DC) sources cannot be accurately resolved unless the receiver array has angular coverage to sample both sides of the shear failure plane. If the source is DC, the inversion can result in a CLVD mechanism that is overestimated by up to ~40% and if the source is CLVD, the DC mechanism can be overestimated by ~20%. Errors in the inversion results are interpreted to be because of the lack of receiver angular coverage of the source rather than possible errors associated with source mislocation. The use of the deviatoric assumption decreases the error in the resolved source mechanism by ~30-~40%, however, this increases the error in the resolved source strike to ~15°-~35°. For pure shear sources, 5% VTI anisotropy in the medium has minimal effect on source orientation (<15°) but can introduce 25-50 m of error in the source location. The neglect of anisotropy in moment tensor inversion has a greater effect (~40% variation) on the estimated source mechanism for pure CLVD sources than for pure DC sources.
The use of chemical diverters in refracturing operations has been increasing and taking the place of mechanical diverters, which were a prevailing technique for years. Chemical diverters consist of particles or liquid that can temporarily clog pre-existing fractures, allowing diversion of the fracturing fluid to create new fractures inside the reservoir and generate a more complex fracture network. The success or failure of a re-stimulation treatment largely depends on the diverter placement and effective isolation of previous fractures. In this work, we propose a novel class of materials as a diverting agent that after pumping into the formation expands to temporarily plug the existing fractures and allow the frac energy to concentrate on generating new fracture strands. Biodegradation and chemical dissolution can be utilized at the end of the treatment to resume the flow from isolated fractures.
Proof-of-concept experiments were carried out using a particle-plugging apparatus to demonstrate the bridging ability of the expandable diverter. The fracture sealing process is observed with the steep increase in the fluid pressure. In order to further tune the performance of this diverter and simulate its performance in reservoir conditions, we developed a numerical model to simulate its placement and expansion. The coupled computational fluid dynamics-discrete element method approach can track the diverting particles individually and simulate the frac fluid flow within the fractures. Multiple scenarios were tested, with different particle sizes and networks of fractures.
Refracturing operations have the potential to extend the production time in unconventional reservoirs with minimum capital investment. These reservoirs are known for having steep decline rates. If there is a considerably small stimulated rock volume (SRV) around the well and the reservoir still has a potential to produce hydrocarbons, these wells can be re-stimulated through refracturing. Re-stimulation is considerably less costly in comparison to drilling and completing a new well. Refracturing can increase the production rate for 2-3 times with a small capital cost.
ABSTRACT: Lost circulation can be a very serious problem while drilling especially in naturally fractured formations. Lost circulation may have serious safety consequences and heavy financial costs in the form of losing mud fluid to the fractures, wellbore stability issues and losing rig time while dealing with the problem. Despite recent advances, lost circulation materials used in the field still have disadvantages such as plugging tools due to the large size of the particles, damaging production zones and failure to minimize lost circulation when heavy mud columns exists in the annulus. In this work, we introduce a new class of “Smart Lost Circulation Materials” to effectively seal the fractures and minimize lost circulation by increasing hoop stress. Our smart LCMs are made out of thermoset shape memory polymers which are activated upon exposure to the formation’s in situ temperature that causes expansion and acts as an effective seal for the fractures. The physical properties of our smart lost circulation materials prevent damage to production zones and tool plugging. In addition, the expansive property of the smart LCM provides compressional forces that strengthen the wellbore by artificially reducing the fracture gradient. We conducted a series of experiments using a HPHT particle-plugging apparatus (PPA) to measure the sealing efficiency of the smart LCMs. In addition, a fully coupled CFD-DEM model is developed to further study the effectiveness of various particle size distributions and the corresponding stress release to improve the design of this product.
One of the problems in rotary drilling is lost circulation. In order to transport cuttings and cool the bit, drilling fluids are supposed to be circulated down to the bottomhole and come back to the surface (White, 1956). When lost circulation occurs, drilling fluids are lost. To stop further fluid loss, loss circulation materials (LCMs) have to be added to the mud. This kind of incidents may have a heavy financial and environmental burden, which justifies the high price of LCM products. It would also increase the high cost of nonproductive rig time that is very valuable (Whitfill and Hemphill, 2003). The US Department of Energy reported in 2010 that on average 10% to 20% of the cost of drilling high-pressure, high temperature wells is spent on mud losses. Above all, lost circulation can lead to mud levels falling, which can cause an underbalance pressure state of the well. In severe cases, it may lead to a kick or even a blowout (Arshad et al., 2014). Instances of lost circulation usually occur in cavernous, karst, highly permeable and naturally fractured formations (Al-Saba et al., 2014). If lost-circulation zones are anticipated, preventive measures should be taken by treating the mud with loss of circulation materials (LCMs) and preventive tests such as the formation integrity test should be performed to better define the mudweight window to limit the possibility of loss of circulation. Hence, lost circulation is a very important issue which has led to a lot research dedicated to minimize its negative impacts and the biggest breakthrough has been LCMs. They are designed to seal fractures and minimize mud loss. The seven categories of LCMs classified by Nygaard et al. (2014) are: fibrous, granular, flaky, acid/water soluble, mixture, high fluid loss LCM squeeze, swellable/hydratable LCM combinations and nanoparticles. Each material varies in its chemical properties, flexibility, shape and the way they seal the fracture.
An integrated cohesive modeling is proposed to analyse hydraulic fracturing jobs in the presence of a natural fracture network. A propagating hydraulic fracture may arrest, cross, or divert into a pre-existing natural fracture depending on fracture properties of rock, magnitude and direction of principal rock stresses, and angle between fractures. Activation of natural fractures during fracturing treatment improves the effectiveness of the stimulation tremendously. Here, we present an integrated methodology initiated with lab scale fracturing properties using Semi-Circular Bending Test
Hydraulic fracturing served as the principal technique to improve production in low permeability unconventional reservoirs in the last decade. Through core and outcrop studies, advanced logging tools, microseismic mapping and well testing analyses, it has further revealed the complexity of induced fracture network in the presence of natural fractures. Although most natural fractures are cemented by precipitations due to diagenesis, they can be reactivated during fracturing treatments and serve as preferential paths for fracture growth. However, current technologies for post-treatment assessment are incapable of accurately determine fracture geometry or even estimating the distribution of pre-existing natural fractures. Despite significant advances in numerical modelling of the problem, these models require an accurate description of natural fractures, which is often unknown to operators. Moreover, these numerical modeling techniques usually do not incorporate post-treatment data to reflect actual reservoir characteristics. This research proposes an innovative data integration workflow to estimate the characteristics of natural fractures based on formation evaluations, microseismic data, treatment data and production history. Least- square modeling approach is utilized to define possible realizations of natural fractures from selected double-couple microseismic events. Forward modeling incorporating Discrete Fracture Network will subsequently be used for matching treatment data and screening generated fracture realizations. Reservoir simulation tools will also be used thereafter to match the production data to further evaluate the fitness of natural fracture realizations. This workflow is able to integrate data from multiple aspects of the reservoir development process, and results from this workflow will provide both geologist and reservoir engineers an assessment tool for evaluating and modeling naturally fractured reservoirs.
Recent examples of hydraulic fracture diagnostic data suggest complex, multi-stranded hydraulic fractures geometry is a common occurrence. This reality is in stark contrast to the industry-standard design models based on the assumption of symmetric, planar, bi-wing geometry. The interaction between pre-existing natural fractures and the advancing hydraulic fracture is a key condition leading to complex fracture patterns. Performing hydraulic fracture design calculations under these less than ideal conditions requires modeling fracture intersections and tracking fluid fronts in the network of reactivated fissures. Whether a hydraulic fracture crosses or is arrested by a pre-existing natural fracture is controlled by shear strength and potential slippage at the fracture intersections, as well as potential debonding of sealed cracks in the near-tip region of a propagating hydraulic fracture. We present a complex hydraulic fracture pattern propagation model based on the Extended Finite Element Method (XFEM) as a design tool that can be used to optimize treatment parameters under complex propagation conditions. Results demonstrate that fracture pattern complexity is strongly controlled by the magnitude of anisotropy of in situ stresses, rock toughness, and natural fracture cement strength as well as the orientation of the natural fractures relative to the hydraulic fracture. Analysis shows that the growing hydraulic fracture may exert enough tensile and shear stresses on cemented natural fractures that they may be debonded, opened and/or sheared in advance of hydraulic fracture tip arrival, while under other conditions, natural fractures will be unaffected by the hydraulic fracture. Detailed aperture distributions at the intersection between fracture segments shows the potential for difficulty in proppant transport under complex fracture propagation conditions.
Hydraulic fracture diagnostics have highlighted the potentially complex natural of hydraulic fracture geometry and propagation. This has been particularly true in the cases of hydraulic fracture growth in naturally fractured reservoirs, where the induced fractures interact with pre-existing natural fractures. A simplified numerical model has been developed to account for mechanical interaction between pressurized fractures, and to examine the simultaneous propagation of multiple (>2) hydraulic fracture segments. Fracture intersection is presumed to communicate the hydraulic fracturing fluid to the natural fracture, which then takes up the continued propagation. Simulations for multi-stage horizontal well treatments and single stage vertical well treatments show that fracture pattern complexity is strongly controlled by the magnitude of the hydraulic fracture net pressure relative to the in situ horizontal differential stress as well as the geometry of the natural fractures. Analysis of the neartip stress field around a hydraulic fracture also indicates that induced stresses may be high enough to debond sealed natural fractures ahead of the arrival of the hydraulic fracture tip.