Wellbore Fracture Research Articles

Wellbore Geomechanics of Extended Drilling Margin and Engineered Lost-Circulation Solutions

SummaryWellbore tensile failure is a known consequence of drilling with excessive mud weight, which can cause costly events of lost circulation. Despite the successful use of lost-circulation materials (LCMs) in treating lost-circulation events of the drilling operations, extensions of wellbore-stability models to the case of a fractured and LCM-treated wellbore have not been published. This paper presents an extension of the conventional wellbore-stability analysis to such circumstances. The proposed wellbore geomechanics solution revisits the criteria for breakdown of a fractured wellbore to identify an extended margin for the equivalent circulation density (ECD) of drilling. An analytical approach is taken to solve for the related multiscale and nonlinear problem of the three-way mechanical interaction between the wellbore, fracture wings, and LCM aggregate. The criteria for unstable propagation of existing near-wellbore fractures, together with those for initiating secondary fractures from the wellbore, are obtained. Results suggest that, in many circumstances, the occurrence of both incidents can be prevented, if the LCM blend is properly engineered to recover certain depositional and mechanical properties at downhole conditions. Under such optimal design conditions, the maximum ECD to which the breakdown limit of a permeable formation could be enhanced is predicted.

Drilling fluid loss control via implementing the FMI and DSI logs to protect environment

Implementing the drilling fluids in drilling operations is of paramount importance owing to the variety of applications and benefits they provide. Materials added to drilling fluid could cause numerous environmental problems in soil and water resources, and these problems are more pronounced in offshore as compared to land fields. Heavy metals such as mercury, barium, arsenic, lead, and nickel exist in drilling fluid, which bring detrimental damages to the environment. Moreover, heavy metals exist in oil-based muds due to presence of oil where their nickel and vanadium are much greater than other heavy metals. Additive materials and heavy metals existing in drilling fluid could pose irreparable environmental damage if fluid loss into the formation occurs. Regarding to the fact that drilling fluid loss occurs via the open fractures in the wellbore, the main aim of this study is to evaluation of wellbore fractures via implementing the FMI log and fracturing pressure using the slowness of compressional and shear waves. A total of 61 fractures in Dalan formation and 72 fractures in Kangan formation are interpreted and fracturing pressure for these formations, ranges between 8400 and 9450 psi. Implementing the results obtained from this study, drilling fluid loss into the formation and subsequent environmental damage could be prohibited via controlling the pumping pressure and density variation of drilling fluid in accordance with the formation fracturing pressure.

Numerical investigation of a novel hypothesis for fracture termination and crossing, with applications to lost circulation mitigation and hydraulic fracturing

We investigate a novel hypothesis regarding the process of hydraulic fracture termination against a preexisting frictional interface. According to current understanding, crossing occurs when small tensile fractures form ahead of the crack tip, on the other side of the frictional interface, before the concentration of stress at the crack tip causes slip along the interface. Slip blunts the concentration of stress at the crack tip and causes termination. Existing crossing criteria assume that the incipient fractures ahead of the crack tip form instantaneously once the effective stress is sufficiently tensile. However, there is a poroelastic response that causes a reduction in pressure in response to opening. This is counteracted by flow into the crack from the surrounding matrix. In very low matrix permeability formations (shale, coalbed methane, etc.), flow of fluid inward from the matrix is slow, and the opening of these incipient fractures may require a non-negligible amount of time. Using the hydro-mechanical discrete fracture network simulator CFRAC, we performed a series of numerical simulations to qualitatively investigate this process. The simulations confirm that poroelastic response could affect incipient fracture initiation and hydraulic fracture crossing. Based on this mechanism, we developed a heuristic modification to an existing crossing criterion. We applied the new criterion to investigate an injection sequence for prevention of lost circulation in fractured, low matrix permeability formations. Lost circulation occurs if wellbore fluid pressure exceeds the minimum principal stress, causing fluid loss due to propagation of a hydraulic fracture. In our proposed injection sequence: (1) injection is performed at high rate to create near wellbore fracture network complexity and then (2) viscous fluid is injected into the newly formed fractures to create resistance to flow. The simulations show that this sequence may be able to mitigate lost circulation and create a stress cage around the wellbore.

The Stability of Inclined and Fractured Wellbores

SummaryThe theory of linear-elastic fracture mechanics is used to develop an analytical solution for a wellbore in an isotropic elastic medium when drilled inclined to a general state of 3D far-field stress, and attached to which are an arbitrary number of N straight and axially aligned fractures. Axial alignment refers to the special case where the borehole axis is the existing common interface of all planes defined by the fracture faces. The solution uses a familiar load decomposition and coordinate-transform scheme. Within the fracture-mechanics context of the analysis, this scheme translates into a set of three fundamental subproblems comprising a uniaxial stress problem, together with an in-plane mixed mode (Modes I and II), and a Mode III antiplane-crack/cavity-interaction problem.The overall solution is obtained by superposing the solutions to these subproblems. A numerical example is presented to demonstrate its usefulness in the stability analysis of inclined and fractured wellbores. Attention has been directed toward the underlying significance that the results would bring in fundamental understanding of lost-circulation events. For this purpose, the criteria for a possible extended margin of the mud weight that secures stable states of a fractured wellbore are recognized and quantified. These criteria include the wellbore-wall refracturing and the existing fractures propagation.

Analysis of Fracture Initiation Pressure of Horizontal Well at Anisotropic Formation Using Boundary Element Method

With the influence of bedding plane, the mechanical properties of bedded rocks, such as shale and coal rock at vertical and parallel bedding direction show comparatively significant difference. Therefore, compared with homogeneous rocks, bedded rocks exhibit obvious anisotropic mechanical properties. Currently, most fracture initiation pressure prediction models simplify rock to homogeneous dielectric elastomer, which is inapplicable to calculate wellbore fracture initiation pressure at bedded stratums. Given that the mechanical properties of bedded rocks at bedding plane direction are the same, this paper established a calculation model of horizontal well fracture initiation pressure in the anisotropic formation and set up a numerical solution method of circumferential stress around the borehole by means of using boundary element method. In addition, a calculation method for fracture initiation pressure based on tensile strength criterion and simplex algorithm was also proposed. The research results indicate that: In the case of high elasticity modulus anisotropy ratio, the wellbore fracture initiation pressure is low; when the elasticity modulus at vertical bedding direction is greater than that at parallel bedding direction, fracture initiation pressure decreases with the increase of bedding dip angle; the shape of wellbore has imposed an significant influence on fracture initiation pressure. For non-circular wellbore, fracture initiation pressure increases with the increase of length-width ratio in the case of smaller ovality. When wellbore shape transforms from equiaxial circle to long and narrow ellipse, fracture initiation pressure decreases with the increase of stress concentration level. Thus, this paper performed calculation and comparison with classical solutions for particular cases similar to isotropic body of stratum using the model established which verified the validity of the proposed theory. According to the research results, a new method for precise calculation of fracture initiation pressure of horizontal well at bedded stratum was provided.

Effect of CO2-induced reactions on the mechanical behaviour of fractured wellbore cement

Geomechanical damage, such as fracturing of wellbore cement, can severely impact well integrity in CO2 storage fields. Chemical reactions between the cement and CO2-bearing fluids may subsequently alter the cement’s mechanical properties, either enhancing or inhibiting damage accumulation during ongoing changes in wellbore temperature and stress-state. To evaluate the potential for such effects, we performed triaxial compression tests on Class G Portland cement, conducted at down-hole temperature (80 °C) and effective confining pressures ranging from 1 to 25 MPa. After deformation, samples displaying failure on localised shear fractures were reacted with CO2–H2O, and then subjected to a second triaxial test to assess changes in mechanical properties. Using results from the first phase of deformation, baseline yield and failure criteria were constructed for virgin cement. These delineate stress conditions where unreacted cement is most prone to dilatational (permeability-enhancing) failure. Once shear-fractures formed, later reaction with CO2 did not produce further geomechanical weakening. Instead, after six weeks of batch reaction, we observed up to 83% recovery of peak-strength and increased frictional strength (15%–40%) in the post-failure regime, due to carbonate precipitation in the fractures. As such, our results suggest more or less complete mechanical healing on timescales of the order of months.

Analysis of Fractured Reservoir Structure by Interpretation of FMI and VSP Logs

Imaging technology into the well is the tools for logging system, interpretation of data obtained from the well and to create the image with high resolution from the wells. This technology creates an accurate image (screenshot tools and the vertical seismic) on structural characteristics, layering, fractures, faults, texture and secondary porosity play an important desirable role in describing the reservoir. In the carbonate reservoirsthat most of Iran reservoirs are included in this type fractures are the most important factor in the production of these reservoirs. In the fractured carbonated reservoirs faults and folds makes unwanted changes in the structure of these reservoir. Structural complexities occur at different scales. For example, major faults and the original boundaries between formations are visible on the surface seismic data. But small-scale changes and faults in seismic data cannot be determined and it is essential to use small-scale of data and information sources. For achieving to these purposes it can be combined the result of small-scale data such as internal wellbore seismic VSP (vertical seismic profile) that having separating power in meter limit and FMI (formation micro imager) imaging logs that having separating limit in centimeter limit that could be able to modeling structural complexities and distribution of fractures around well. It should be noted that identifying occurrences around the wellbore is very important in drilling, completion procedures and development programs. FMI (formation micro imager) logs can be directly determined the inverted changes of wellbore layers and formation structures and also was an important factor for stratifying layers and determining the lithology of oil and gas explorations that can be determined the wellbore fractures, inclination and direction by using its interpretation. Moreover VSP (vertical seismic profile) logs is the way that generated signals at the surface are received by the geophone at different depth levels in the wells, which by its interpretation; changes in wellbore direction, velocity profiles, faults with higher accuracy around the wells and fractures around the well can be determined.

Elucidating hydraulic fracturing impacts on groundwater quality using a regional geospatial statistical modeling approach

Hydraulic fracturing operations have been viewed as the cause of certain environmental issues including groundwater contamination. The potential for hydraulic fracturing to induce contaminant pathways in groundwater is not well understood since gas wells are completed while isolating the water table and the gas-bearing reservoirs lay thousands of feet below the water table. Recent studies have attributed ground water contamination to poor well construction and leaks in the wellbore annulus due to ruptured wellbore casings. In this paper, a geospatial model of the Barnett Shale region was created using ArcGIS. The model was used for spatial analysis of groundwater quality data in order to determine if regional variations in groundwater quality, as indicated by various groundwater constituent concentrations, may be associated with the presence of hydraulically fractured gas wells in the region. The Barnett Shale reservoir pressure, completions data, and fracture treatment data were evaluated as predictors of groundwater quality change. Results indicated that elevated concentrations of certain groundwater constituents are likely related to natural gas production in the study area and that beryllium, in this formation, could be used as an indicator variable for evaluating fracturing impacts on regional groundwater quality. Results also indicated that gas well density and formation pressures correlate to change in regional water quality whereas proximity to gas wells, by itself, does not. The results also provided indirect evidence supporting the possibility that micro annular fissures serve as a pathway transporting fluids and chemicals from the fractured wellbore to the overlying groundwater aquifers.

Experiment simulation of hydraulic fracture in colliery hard roof control

Hydraulic fracture geometry is of paramount importance to enhance fracture effect in colliery hard roof control. Near wellbore complexity often resulted in low lateral dimension of induced fracture hence the fracking effect of the treatment. In the past, near wellbore fracture geometry is mainly believed to be controlled by the interaction between hydraulic fracture initiation and natural fracture infiltration/opening. Recently, lab experiments have proved that transverse notch plays a role in lowering breakdown pressure and also in reducing near wellbore complexity. Besides, colliery hard roofs are often over-pressured, therefore, with the increase of pore pressure, the influence caused by stress difference is weakened, and the role of notch becomes significant. In this paper, a series of lab experiments are conducted to gain in-depth understanding of the role transverse notch plays on near wellbore geometry and fracture reorientation. Hydraulic fracture process is physically simulated by injecting water (green dyed) at some certain rate into a pre-installed tube in a block (300×300×300 mm) under tectonic stress condition. Different notch parameters and fracturing regimes are used to make comparison. The notch changes the local stress and strain field in the blocks and affects the way blocks deform and fail. Post-mortem analysis and photo image of the block clearly show: (i) the length and angle of initial notch play a role in determining: near wellbore geometry and fracture reorientation; (ii) near wellbore fracture complexity may be reduced by making a longer initial notch and picking an appropriate notch angle; (iii) better understanding can be achieved by conducting further researches under normal stress condition and taking more factors into consideration.

English

English

Optimized Design and Use of Induced Complex Fractures in Horizontal Wellbores of Tight Gas Reservoirs

Multistage hydraulic fracturing is being increasing use in the establishment of horizontal wells in tight gas reservoirs. Connecting hydraulic fractures to natural and stress-induced fractures can further improve well productivity. This paper investigates the fracture treatment design issues involved in the establishment of horizontal wellbores, including the effects of geologic heterogeneity, perforation parameters, fracturing patterns, and construction parameters on stress anisotropy during hydraulic fracturing and on natural fractures during hydraulic fracture propagation. The extent of stress reversal and reorientation was calculated for fractures induced by the creation of one or more propped fractures. The effects of stress on alternate and sequential fracturing horizontal well and on the reservoir’s mechanical properties, including the spatial extent of stress reorientation caused by the opening of fractures, were assessed and quantified. Alternate sequencing of transverse fractures was found to be an effective means of enhancing natural fracture stimulation by allowing fractures to undergo less stress contrast during propagation. The goal of this paper was to present a new approach to design that optimizes fracturing in a horizontal wellbore from the perspectives of both rock mechanics and fluid production. The new design is a modified version of alternate fracturing, where the fracture-initiation sequence was controlled by perforation parameters with a staggered pattern within a horizontal wellbore. Results demonstrated that the modified alternate fracturing performed better than original sequence fracturing and that this was because it increased the contact area and promoted more gas production in completed wells.

Energetics Applications for the Oil and Gas Industry

Energetics Applications for the Oil and Gas Industry

Improving fracture initiation predictions of a horizontal wellbore in laminated anisotropy shales

Increasingly prominent unconventional petroleum resources tend to occur in formations with laminated heterogeneity. The predominant laminated heterogeneity in tight gas shale reservoirs results in considerable variability in the elastic properties along the orientations parallel and perpendicular to the bedding direction.By incorporating the anisotropic elastic deformation and pore hydro-mechanical coupling effects, a 3D numerical model of fracture initiation from a perforated horizontal wellbore is established. A sensitivity analysis is proposed to evaluate the effects of the anisotropic mechanical behavior and in situ stress conditions on the fracture initiation pressure (FIP) and location of an initial rupture. Comprehensive analysis results revealed elastic anisotropy results in the complex near-wellbore stress concentrations, proved by the fact that the near wellbore fracture tortuosity increases as the perforation azimuth increases, which is not observed in traditional isotropic rocks. Furthermore, perforation parameters including perforation density, perforation diameter, and perforation depth, are also analyzed assuming elastic anisotropy conditions. In addition, a stronger Young's modulus anisotropy causes lower fracture initiation pressure and lower fracture tortuosity at the wellbore face, while the impact of the Poisson's ratio anisotropy is relatively small. Changes in the in situ stress conditions have a significant effect on the fracture initiation pressure whether the rock is an isotropic or anisotropic formation. Numerical simulation results indicate that near-wellbore modeling in horizontal completions in an anisotropic shale is a necessary step for predicting and controlling the potential problems during fracturing treatment and avoiding erroneous completion decisions based on traditional isotropic models.

Uncertainty evaluation of wellbore stability model predictions

Abstract There is an increasing concern in the oil and gas industry regarding wellbore stability problems. The need to improve well operations becomes more imperative as the operators move towards more challenging and harsher environments such as ultra-deep waters and high-pressure and high-temperature (HPHT) fields. Different inconsistencies affect many previous wellbore stability analyses, resulting in incorrect results, or results that cannot be extended to other well configurations by well planners. Typical wellbore fracture and collapse models provide single point estimates of the geopressures. The model input data may be uncertain. Failure to capture these uncertainties has led to poor predictions. The purpose of this work is to investigate typical fracture and collapse models with respect to in accuracies in the input data with a stochastic method. Uncertainties in the input data, which include in-situ stresses, rock strength data, and pore pressure will be evaluated, to show how these contribute to the cumulative uncertainties in the model predictions. In this approach, the input parameters are assigned appropriate probability distributions. The distributions are then applied in the wellbore stability models. By means of Monte Carlo simulations, the uncertainties are propagated and the histograms of the outputs are generated. Two types of distributions – triangular and uniform – are applied, to see how the types of input-parameter distributions that are assumed influence the model predictions. Sensitivity analysis is also conducted. This is to ascertain the most significant input factors, which are largely responsible for the cumulative uncertainties or variabilities in the critical fracturing and collapse pressures. The proposed methodology can help in reducing many drilling problems such as circulation loss, stuck pipe, and well collapse. As a result, the industry may save much non-productive time. In addition, well planners will have improved information to make critical decisions.

Challenges in hydraulic fracturing from perforated boreholes in unconventional reservoirs

In recent years, with the evolution of unconventional reservoirs, hydraulic fracturing has been applied to tight sandstone and shale formations to improve the hydrocarbon production. The application of hydraulic fracturing in cased boreholes is always associated with many difficulties because the fracture has to be initiated from the perforations. There have been many cases of improper fracture initiation in tight formations, which have then resulted in premature screen out, and have not improved reservoir production. In this study, initiation of hydraulic fracturing from a perforated tunnel was studied numerically using a finite element method. The numerical model was generated to represent a laboratory experimental test, which has been carried out on tight concrete cubic samples. A perforated wellbore in a linearly elastic tight formation was modelled using Abaqus software through three-dimensional numerical analysis. Two different perforation orientations were considered to analyse the fracture initiation pressure (FIP) and the location and initial direction of the crack. Different far field stresses were considered to study the effect of in-situ stresses and perforation directions on the fracture initiation mechanism. The results were then compared to laboratory and analytical outcomes, and good agreement was observed. The results provide a better understanding on how the stress regime, stress anisotropy, and perforation orientation could affect the pressure and geometry of fracture initiation in tight formations. Based on the outcomes of this study, better strategies can be decided for perforating a cased wellbore in a tight formation so that lower FIP is experienced and a better near wellbore fracture is created.

Perforation optimization of hydraulic fracturing of oil and gas well

Considering the influences of fluid penetration, casing, excavation processes of wellbore and perforation tunnels, the seepage-deformation finite element model of oil and gas well coupled with perforating technique is established using the tensile strength failure criterion, in which the user-defined subroutine is developed to investigate the dynamic evolvement of the reservoir porosity and permeability. The results show that the increases of perforation angle and decreases of perforation density lead to a higher fracture initiation pressure, while the changes of the perforation diameter and length have no evident influences on the fracture initiation pressure. As for initiation location for the fracture in wellbore, it is on the wellbore face while considering the presence of the casing. By contrast, the fractures firstly initiate on the root of the tunnels without considering casing. Besides, the initial fracture position is also related with the perforation angle. The fracture initiation position is located in the point far away from the wellbore face, when the perforation angle is around <TEX>$30^{\circ}$</TEX>; however, when the perforation angle is increased to <TEX>$45^{\circ}$</TEX>, a plane fracture is initiated from the wellbore face in the maximum horizontal stress direction; no fractures was found around perforation tunnels, when the angel is close to <TEX>$90^{\circ}$</TEX>. The results have been successfully applied in an oilfield, with the error of only 1.1% comparing the fracture initiation pressure simulated with the one from on-site experiment.

The Inflow Performance of a Multiple-fractured Horizontal Wells Based on a Discrete-fracture Model

The mathematical unsteady flow model of a multiple-fractured horizontal well in box-shaped reservoir is developed. The Darcy law is employed to describe the fluid flow in matrix media and fractures, while the Hagen-Poiseuille law is used to describe the flow within horizontal well. Then the idea of discrete-fracture model is adopted to simplify the integral form and improve the computational efficiency, where fracture and horizontal wellbore are assumed as 2D plane and 1D line, respectively. Finally, the numerical bottom pressure solution is obtained, and the accuracy of this method is verified by comparing it with a classic analytical method.

Welltest analysis of hydraulically fractured tight gas reservoirs: a field example from Perth Basin, Western Australia

Welltest interpretation requires the diagnosis of reservoir flow regimes to determine basic reservoir characteristics. In hydraulically fractured tight gas reservoirs, the reservoir flow regimes may not clearly be revealed on diagnostic plots of transient pressure and its derivative due to extensive wellbore storage effect, fracture characteristics, heterogeneity, and complexity of reservoir. Thus, the use of conventional welltest analysis in interpreting the limited acquired data may fail to provide reliable results, causing erroneous outcomes. To overcome such issues, the second derivative of transient pressure may help eliminate a number of uncertainties associated with welltest analysis and provide a better estimate of the reservoir dynamic parameters. This paper describes a new approach regarding welltest interpretation for hydraulically fractured tight gas reservoirs—using the second derivative of transient pressure. Reservoir simulations are run for several cases of non-fractured and hydraulically fractured wells to generate different type curves of pressure second derivative, and for use in welltest analysis. A field example from a Western Australian hydraulically fractured tight gas welltest analysis is shown, in which the radial flow regime could not be identified using standard pressure build-up diagnostic plots; therefore, it was not possible to have a reliable estimate of reservoir permeability. The proposed second derivative of pressure approach was used to predict the radial flow regime trend based on the generated type curves by reservoir simulation, to estimate the reservoir permeability and skin factor. Using this analysis approach, the permeability derived from the welltest was in good agreement with the average core permeability in the well, thus confirming the methodology’s reliability.

Estimates of Fracture Lengths in an Injection Well by History Matching Bottomhole Pressures and Injection Profile

Summary An injection-well model is presented and used to history match a field injector's bottomhole pressures (BHPs) and injection profile (injection rate into each layer), taking into account plugging of formation caused by suspended solids in the injection water, poro- and thermoelastic stresses, injector shut-ins/restarts, and changes in both the injection rates and the average reservoir pressure. Fracture lengths and injection profile are estimated for a field injector as a case study. The injection-well fracture model is very similar to the Perkins and Gonzalez (1985) model except that it has integrated a more comprehensive and experimentally tested internal filtration model (Rajagopalan and Tien 1976; Pang and Sharma 1997; Gadde and Sharma 2001; Suri 2000; Wennberg and Sharma 1997) for calculating permeability reduction. It has also added a pressure-transient model that makes the earlier reservoir flow models more accurate. The solids deposition is modeled using a filtration model (Rajagopalan and Tien 1976). The fluid flow in the reservoir is modeled using three approximated composite zones with uniform saturations and average mobilities, and the pressure for the fractured wellbore is calculated with the help of Gringarten's (1974) infinite-conductivity solution. The induced-fracture lengths are calculated on the basis of the Perkins and Gonzalez fracture-propagation model (1985) that accounts for the thermal and poroelastic stresses. The model is developed into a semianalytical numerical simulator that can predict and history match an injector's daily BHP, fracture lengths, and injection profile. Future estimates of pump pressures, BHP, injectivity, skin, front locations, fracture lengths, and injection profile can be obtained from this model. Both short-term pressure transients and long-term pseudosteady pressures observed over several years of injection can be history matched to capture effects that are important at both short and long time scales. Finally a field-case injection-well study is presented in which BHP and injectivity are history matched over a period of 3 years. We show that the model can be used to estimate the minimum horizontal stresses in the layers if they are not known. Estimates of fracture lengths, fraction of flow, permeability reduction, and skin and front locations are also obtained. There is significant uncertainty in the results because of uncertainty in the model inputs and in the completeness of the physics of the model of fracturing itself. Both the solids deposition and the opening/closing of the injection-induced fractures had to be accounted for to obtain the history match. The layer/sand stresses and the water quality are the most important parameters that determine the well's injectivity, fracture growth, and injection profile. Microseismic surveys and PLTs are needed to confirm fracture lengths in injection wells.

Study on Mechanical Model of Borehole Confining Pressure of Dual-Porosity Considering Seepage

Accurately describing wellbore sur-rounding rock mechanics state plays an important role in the research on sidewall stability. Considering the failure behavior of the wellbore rock mass, we divide the rock area to failure zone, damage zone and elastic range. We establish dual porosity with fracture wellbore rock stress calculation model according to failure theory. We calculate an production well ambient stress in a given block, the result of which coincides with actual result measured in field.