Fluid flow and heat transfer during staged multi-cluster fracturing treatments along horizontal wells — Application for hydraulic fracture characterization using distributed temperature sensing

Evaluation of geothermal energy extraction in Enhanced Geothermal System (EGS) with multiple fracturing horizontal wells (MFHW)

The effects of fractures on porous flow and heat transfer in a reservoir of a U-shaped closed geothermal system

Summary Wellbore damage commonly is accounted for by an apparent skin factor. A better relative index for determining the efficiency with which a well has been drilled and completed is the "flow efficiency," the ratio of a well's actual PI to ideal PI. The flow effieicny of horizontal wells is derived assuming steady-state flow of an incompressible fluid in a homogeneous, anisotropic medium. A comparison between the flow efficiencies of vertical and horizontal wells indicates that permeability reduction around the wellbore is less detrimental to horizontal wells. This paper shows that the effect of damage around a horizontal wellbore is reduced slightly by increasing the well length. Conversely, if the vertical permeability is less than the horizontal permeability, the anisotropy ratio, kH/kV, magnifies the influence of formation damage near the horizontal wellbore. Examples of flow efficiency calculations assuming a formation damage or a formation collapse around a liner in poorly consolidated formations are provided for horizontal and vertical wells. Introduction Many technical aspects of horizontal wells have been compared with more-conventional wells (vertical or deviated) to determine their effectiveness as a new alterative to reach and produce oil and gas reservoirs. The most obvious comparison, well-documented in the literature,1,2 is the productivity performance of horizontal wells vs. unstimulated or fully stimulated(acidized/fractured) vertical wells. Two of the newest application areas to compare horizontal and vertical wells and to adapt methods applied to conventional wells to horizontal wells are hydraulic fracturing and matrix acidizing. Recent papers have expressed different viewpoints on the role of formation damage in the performance of horizontal wells. Some3,4 suggest that, as horizontal-well length, L, increases, the influence of formation damage on total pressure drop can become negligible, resulting in an additional advantage over vertical wells. Others5 indicate that the damaged zone may affect productivity more in horizontal wells than in vertical wells, and that skin damage sometimes can prevent horizontal-well projects from succeeding. These two opposing interpretations of the influence of formation damage on horizontal-well productivity come from a lack of well-defined criteria (reservoir and well characteristics) to quantify the effect of formation damage on the flow efficiency of horizontal wells. The objective of this paper is to provide a basis for comparing the flow efficiencies of vertical and horizontal wells. Analytical expressions are derived assuming steady-state flow of an incompressible fluid in a homogeneous anisotropic medium. Both the top and bottom horizontal boundaries of the reservoir have no-flow conditions. The comparison considers an altered zone of the same radius and reduced permeability around the vertical and horizontal wellbores. Flow Efficiency of Vertical Wells van Everdingen6 and Hurst7 quantified the pressure drop caused by a permeability reduction near and at the wellbore in terms of the skin factor, sV: Equation 1 Hawkins8 showed that this skin factor could be related to the altered zone of permeability ks, which extends to the distance rs into the formation, by Equation 2 and that the flow efficiency, EV, the ratio of actual well PI to ideal PI (the PI if the permeability were unaltered all the way to the well's sandface), could be expressed in terms of ?ps and the total drawdown, ?pw, as Equations 3 and 4 Flow Efficiency of Horizontal Wells Merkulov9 originally reported the expression for the ideal PI of a horizontal well in an isotropic reservoir. Giger1 and Joshi2 presented the pressure profile created by 3D steady-state flow to a horizontal well located inside an ellipsoidal drainage area (Fig. 1a). Their solution, which is suitable for horizontal wells that have small lengths compared with the drainage radius, was extended by Giger1 to the case of a rectangular drainage area fed laterally (Fig. 1b) to account for wells that have large lengths compared with the distance to the feeding boundary. As indicated in Appendix A, the ideal PI of a horizontal well for both geometries in a reservoir of permeability anisotropy ratio ß can be written as Equation 5 with rw=[(1+ß)/2ß]rw and X depending on the shape and dimensions of the area drained by the well.

Coupled wellbore–reservoir heat and mass transfer model for horizontal drilling through hydrate reservoir and application in wellbore stability analysis

The post-fracture-pressure-decay (PFPD) technique is a low-cost method allowing for stage-by-stage hydraulic fracture characterization. The physics of the PFPD method are complex, with data affected by both hydraulic fracture and reservoir properties. Available analysis methods in the literature are oversimplified; reservoir or fracture properties are often assumed to be constant along the horizontal well, and therefore changes in the trend of pressure decay data are attributed to hydraulic fracture or to reservoir properties only. Moreover, methods analogous to those applied to the analysis of conventional diagnostic fracture injection tests (DFITs) are often used and ignore critical mechanisms involved in main-stage hydraulic fracture stimulation. A conceptual numerical simulation study was first conducted herein to understand the key physics involved in main-stage hydraulic fracturing. An analytical model was then developed to account for the dynamic behavior of the hydraulic fracture, pressure-dependent leakoff, proppant distribution, multiple fractures, and propped- and unpropped-closure events. The analytical model is cast in the form of a new straight-line analysis (SLA) method that provides stage-by-stage estimates of the ratio of unpropped fracture surface area to total fracture surface area. The SLA method was validated against numerical simulation results. Moreover, to account for the variation of reservoir properties along the horizontal well, the PFPD model is integrated with DFIT-flowback (DFIT-FBA) tests, performed at some points along the lateral, to obtain a reliable stage-by-stage hydraulic fracture and reservoir characterization approach. The practical application of the proposed integrated approach was demonstrated using PFPD and DFIT-FBA data from a horizontal well completed in 22 stages in the Montney Formation. The numerical simulation study demonstrated that the use of proppant and injection into multiple clusters (creating multiple fractures) results in multiple-closure events. The closure process may start early after the pump-in period at a pressure significantly higher than the minimum in-situ stress. Employing DFIT-based analytical models, which ignore the presence of proppant, causes significant errors in hydraulic fracture and reservoir property estimation. The PFPD field data examined herein exhibited a similar pressure trend to the numerical simulation cases. The ratio of unpropped fracture surface area to total fracture surface area was determined stage-by-stage using the PFPD SLA method, constrained by DFIT-FBA data. Engineers can use this information to optimize hydraulic fracture stimulation design in real-time, optimize well spacing, and forecast production. The cost and time advantages of this diagnostic method make this approach very attractive.

Summary The post-fracture pressure decay (PFPD) technique is a low-cost method allowing for stage-by-stage hydraulic fracture characterization. The analysis of the PFPD data is complex, with data affected by both hydraulic fracture and reservoir properties. Available analysis methods in the literature are oversimplified; reservoir or fracture properties are often assumed to be constant along the horizontal well, and therefore changes in the trend of pressure decay data are attributed to hydraulic fracture or reservoir properties only. Moreover, methods analogous to those applied to the analysis of conventional diagnostic fracture injection tests (DFITs) are often used and ignore critical mechanisms involved in main-stage hydraulic fracture stimulation. A conceptual numerical simulation study was first conducted herein to understand the key mechanisms involved in main-stage hydraulic fracturing. An analytical model was then developed to account for the dynamic behavior of the hydraulic fracture, leakoff, proppant distribution, multiple fractures, and propped- and unpropped-closure events. The analytical model is cast in the form of a new straightline analysis (SLA) method that provides stage-by-stage estimates of the ratio of unpropped fracture surface area to total fracture surface area. The SLA method was validated against numerical simulation results. Moreover, to account for the variation of reservoir properties along the horizontal well, the PFPD model is integrated with DFIT-flowback (DFIT-FBA) tests, performed at some points along the lateral, to obtain a reliable stage-by-stage hydraulic fracture and reservoir characterization approach. The practical application of the proposed integrated approach was demonstrated using PFPD and DFIT-FBA data from a horizontal well completed in 22 stages in the Montney Formation. The numerical simulation study demonstrated that the use of proppant and injection into multiple clusters (creating multiple fractures) results in multiple closure events. The closure process may start early after the pump-in period at a pressure significantly higher than the minimum in-situ stress. Using DFIT-based analytical models, which ignore the presence of proppant, causes significant errors in hydraulic fracture and reservoir property estimation. The PFPD field data examined herein exhibited a similar pressure trend to the numerical simulation cases. The ratio of unpropped fracture surface area to total fracture surface area was determined stage by stage using the PFPD SLA method, constrained by DFIT-FBA data. Engineers can use this information to optimize the hydraulic fracture stimulation design in real time, optimize the well spacing, and forecast the production. The cost and time advantages of this diagnostic method make this approach very attractive.

In this study, a rigorous coupled flow-geomechanics semianalytical approach is presented to analyze flowback data and forecast production performance in multifractured horizontal wells. Hydraulic fracture characterization using post-stimulation flowback data is of critical importance to the quantification of early-time well performance and for efficient development of unconventional reservoirs. However, conventional reservoir (flow) simulators can be challenging to setup for flowback analysis. Further, flow simulators usually approximate stress-dependence of fracture and reservoir parameters, the former of which is particularly important to capture for both the flowback and forward modeling problem, using porosity and transmissibility multipliers. However, in order to apply this approach, transmissibility multipliers must be estimated from laboratory experiments, or used as a history-match parameter, possibly resulting in large errors in performance predictions. The goal of this study is to provide a rigorous, coupled semianalytical workflow for hydraulic fracture characterization from flowback data, that utilizes a 3D coupled flow-geomechanics semi-analytical model as its basis. A 3D semi-analytical coupled flow-geomechanical model is developed to capture the complexities of stress-dependence in order to forecast production performance from multifractured horizontal wells. The model can also be used to derive hydraulic fracture properties from early post-stimulation flowback data. An enhanced fracture region (EFR) conceptual model is applied for approximating complex fracture geometries. The fully-analytical fluid flow and semi-analytical geomechanical models are coupled for both the fracture and reservoir regions. The proposed approach requires simultaneous solutions of the fluid flow model (reservoir simulation) and geomechanics model, the latter capturing the stress and deformation behavior of the fracture and reservoir. Coupling between fluid flow and geomechanics is achieved by updating the pressure and stress-dependent properties through a porosity function (coupling parameter) in the flow model for each region (hydraulic fracture and reservoir) at each iteration step. The coupled flow-geomechanics EFR model is validated with fully-numerical simulation. Fracture properties are estimated by using the proposed inverse model for analyzing flowback (water) data. The new flowback analysis approach is applied to synthetic field data and the results compared with the inputs of the synthetic model. With this model, combined with the semi-analytical coupled flow-geomechanics workflow, a more confident estimate of hydraulic fracture properties is obtained.

The accurate calculation of horizontal and vertical wells' productivity indices is not possible if their respective drainage areas are not estimated accurately. The determination of their respective drainage areas is of great importance in field development when utilizing both horizontal and vertical wells, or when planning to convert some of the vertical wells into horizontal drainholes. This paper suggests the use of a mathematical model describing the interference testing of an active horizontal well in the presence of another active vertical well located in a bounded, homogeneous, and anisotropic oil reservoir in order to estimate the drainage areas of both wells for various combinations of well and reservoir properties. This is the first time this new concept has been introduced to the reservoir engineering discipline. In order to accurately compare horizontal well and vertical well performances, one needs to establish some criteria taking into account the wells' operating conditions. This study has introduced two criteria for the comparative study. These criteria are based on production rate and bottomhole flowing pressure for these wells. This is also the first time in the reservoir engineering discipline that such criteria are used to determine drainage area ratio, production rate ratio, and productivity index ratio ofthese two different types of wells utilizing an analytical model. The values of drainage area ratio, production rate ratio, and productivity index ratio obtained from this new method can be used to determine well spacing and optimum horizontal well length when these two types of wells are to be drilled in the same reservoir. The highest Ahw/Avw and qh /qv ratios correspond to long horizontal wells drilled in thin and isotropic reservoirs developed in a manner that yields a high value of drainage area length compared to drainage area width (i.e., high value of Xe/Ye ratio). It was observed that the advantage of horizontal wells over vertical wells increases when well spacing in a reservoir developed by both horizontal and vertical wells is chosen to be small, such as the one chosen in depleted reservoirs and reservoirs undergoing enhanced oil recovery operations. The results presented in this paper show that the new concept yields drastically different results than the one assumed by Joshi. It is important to note that Joshi's results are based solely on his assumptions regarding the geometry, while the concept introduced in this paper is based on the fundamentals of fluid flow through porous media. Introduction Due to the significant breakthroughs in drilling technology in the early 1980s, horizontal well drilling became an attractive alternative. Horizontal wells have higher productivity than vertical wells in certain reservoirs such as naturally fractured reservoirs, thin reservoirs, low permeability reservoirs, and compartmentalized reservoirs. Efficient implementation of horizontal well technology requires further understanding of the fluid flow behaviour of these wells. The accurate determination of drainage area of horizontal wells in comparison to that of vertical wells for a given set of reservoir parameters is of great importance in field development when utilizing both horizontal and vertical wells.

Summary. This paper discusses the main reservoir engineering and fracture mechanics aspects of fracturing horizontal wells. Specifically, the paper discusses fracture orientation with respect to a horizontal wellbore, locating a horizontal well to optimize fracture height, determining the optimum number of fractures intercepting a horizontal well, and the mechanism of fluid flow into a fractured horizontal well. Introduction Interest in horizontal well drilling and completions has increased during the last few years. The significant advances in drilling and monitoring technology have made it possible to drill, guide, and monitor horizontal holes, making horizontal drilling not only possible but also consistently successful. Most wells have been completed as drainholes. These drainholes have been used in primary production and in EOR. Papers on drilling, completion, well testing, and increased production of horizontal vs. vertical wells have been presented in the petroleum literature. Many papers have dealt with steady-state production increase of horizontal wells over vertical wells Graphs and equations have been presented for calculating steady-state ratios for both fractured and unfractured wells. Ref. 2 provides a recent review of this technology. Other authors have studied the transient behavior of pressure response during a drawdown or a buildup of a drainhole. The literature lacks comprehensive studies on fracturing horizontal wells, and none of the studies cited above discussed this subject. Only Karcher et al. studied production increase caused by multiple fractures intercepting a horizontal hole. Using a numerical simulator, Karcher studied steady-state behavior of infinite-conductivity fractures. Stability of horizontal holes during drilling is another important aspect of horizontal well technology. It has been found that the degree of stability of horizontal holes depends on the relative magnitude of the three principal stresses and the orientation of the wellbore with respect to the minimum horizontal stress. Although productivity of horizontal wells could be two to five times higher than productivity of vertical wells, fracturing a horizontal well may further enhance its productivity, especially when formation permeability is low. Presence of shale streaks or low vertical permeability that impedes fluid flow in the vertical direction could make fracturing a horizontal well a necessity. This paper discusses fracturing horizontal wells from both reservoir engineering and fracture mechanics points of view. Our goal is to shed some light on important aspects of fracturing horizontal wells. Stress Magnitude and Orientation The first parameter to be determined is the fracture orientation with respect to the wellbore. Because fractures are always perpendicular to the least principal stress, the questions actually concern wellbore- and stress-orientation measurements. In what direction will induced fractures occur? What is the anticipated fracture geometry? What is the optimum length of the perforation interval? What is the optimum treatment size? What are the expected fracturing pressures? Data necessary for planning a fracturing treatment are the mechanical properties of the formation, the orientation and magnitude of the least principal stress, the variation in stresses above and below the target formaation, and the leakoff characteristics of the formation. It is commonly accepted that, at depths usually encountered in the oil field, the least principal stress is a horizontal stress. It also can be shown that the induced fracture will be oriented perpendicular to the least principal stress. The result is that a fracture created by a treatment will be in a vertical plane. If the horizontal segment is drilled in the direction of the least stress, several vertical fractures may be spaced along its axis wherever perforations are present. This spacing is one of the design parameters to be selected. Usually, this is investigated with numerical simulators. If the horizontal segment is drilled perpendicular to the least stress, one vertical fracture will be created parallel to the well. Figs. 1 and 2 show fracture direction vs. well direction. When the wellbore is not in one of these two major directions, several scenarios may occur, depending on the angle between the wellbore and the stress direction and on the perforation distribution and density. JPT P. 966⁁

Production enhancement and ultimate recovery improvement have given horizontal wells the edge over vertical wells in many marginal reservoirs. However, it is more expensive to drill and complete a horizontal well than a vertical one. Therefore, to determine the economical feasibility of drilling a horizontal well, engineers need reliable methods to estimate its productivity. After a broad literature review, a simple semi-analytical model has been developed in this study for predicting the productivity of horizontal oil wells. This model couples flow from a box-shaped drainage volume to flow in the wellbore. Along with friction, acceleration and fluid inflow effect, change in flow regime from laminar to turbulent is also taken into account to describe flow in the wellbore. The reservoir inflow model used in this productivity model represents flow in the reservoir using a combination of one-dimensional and two-dimensional models and also considers varying skin along the wellbore to account for the heterogeneity of near wellbore region due to drilling fluid invasion into formation. In addition, reservoir permeability anisotropy and convergence of flow to the wellbore have been taken into account in this inflow model. Comparison of this model with three existing models using field data reveals that the proposed model is more accurate due to more realistic modeling of reservoir inflow and wellbore flow. Semi-analytical nature of this coupling model makes it comprehensive and applicable to reservoirs with varying conditions, especially heterogeneous reservoirs. Moreover, this productivity model can be easily extended to estimate the deliverability of multilateral wells by coupling the inflow performance of individual laterals with hydraulics in build-up sections and the main vertical section. A logical procedure for calculating the deliverability of multilateral wells by using this productivity model is described in this paper. Introduction A worldwide interest exists today in drilling horizontal wells to increase productivity. Productivity of a horizontal well can be greater than that of vertical wells for several reasons. First, horizontal wells can be open to a larger portion of the reservoir than vertical wells. A larger contact area allows lower drawdown to recover more oil and gas. Horizontal wells can be drilled perpendicular to oriented natural fractures and therefore intersect with more fractures. Also, it may be possible to induce multiple hydraulic fractures in a horizontal well. Increased productivity is not the only benefit of horizontal wells; improved sweep efficiency, reduced coning of water or gas and increased drainage area are other advantages of horizontal wells over vertical wells. Therefore, horizontal wells are believed to perform better than their vertical counterparts in thin reservoirs, naturally fractured reservoirs (double-porosity and discretely fractured), reservoirs with gas and water coning problems, reservoirs with favorable vertical permeability anisotropy, offshore environments where various wells are drilled from a central platform, and in various enhanced oil recovery projects. Recent interest in horizontal wells has been accelerating because of improved drilling and completion technology. This has led to increased efficiency and economics in oil recovery. Increases in oil production rate and improvement in ultimate recovery has given horizontal wells the edge over vertical wells in many marginal reservoirs. However, it is more expensive to drill and complete a horizontal well than a vertical one. Therefore, to determine the economical feasibility of drilling a horizontal well, engineers need reliable methods to estimate its expected productivity.

A combination of hydraulic fracturing and horizontal wells is now being used to tap geothermal energy from naturally fractured reservoirs. Fully grid-based numerical models are currently used to simulate heat recovery from enhanced geothermal systems (EGS). Such models require a fine unstructured mesh and are computationally expensive. In this paper we present a computationally efficient model that allows us to accurately simulate fracture propagation, fluid flow, and heat transfer in networks of natural fractures that may be created in naturally fractured geothermal reservoirs. The integrated simulator is developed by combining the displacement discontinuity method (DDM) for fracture propagation in naturally fractured reservoirs with a general Green's function solution for fluid and heat flow from the matrix to the fracture. This eliminates the need to discretize the matrix domain resulting in a very computationally efficient solution. A discrete fracture network (DFN) approach is used to represent the pre-existing natural fractures. The model is first validated against an analytical solution for fluid flow and heat transfer in a rock matrix with a single fracture. The computation time with and without discretizing the rock matrix shows a 100-fold reduction in computation cost with very little loss in accuracy. Parametric studies are conducted to investigate the effect of the distribution of natural fracture density, length, and orientation. The results show that the efficiency of tapping geothermal energy is impacted by geometrical and topological complexities of the fracture network and in particular the connectivity of backbone fractures. It is, therefore, important to optimize (not maximize) the connectivity and complexity of the backbone fracture network. The computationally efficient model presented here provides a practical tool for optimizing operational parameters for efficient geothermal production.

Effect of fracture geometry, topology and connectivity on energy recovery from enhanced geothermal systems

Nanopores to megafractures: Current challenges and methods for shale gas reservoir and hydraulic fracture characterization

Fluctuating flow is widely presented in nuclear power plant operating procedure. When the fluctuating flow occurs in the loop, the fluid flow and heat transfer in the core will be affected, which makes the study of flow fluctuation have more practical significance. With computational fluid dynamics (CFD), characteristics of fluid flow and heat transfer are numerically simulated in a horizontal tube under periodical fluctuating flow. The influences of different factors on the fluid flow and heat transfer are analyzed. The simulation results of steady flow and heat transfer in horizontal tube agree with the traditional empirical correlations’ results, which validates the feasibility of doing this research using CFD simulation. The horizontal tube fluctuation flow and heat transfer with different flow fluctuation periods, fluctuation relative amplitudes and heat fluxes are numerically simulated. The results show that the smaller the flow fluctuation period is, the larger the flow fluctuation relative amplitude we get, and the more evident influence of flow fluctuation on fluid flow and heat transfer can be found. The larger the heat flux is, the larger amplitude of temperature fluctuation of fluid will be. What is more, there is a lag in phase between friction coefficient and velocity, which is not presented between heat transfer coefficient and velocity.

Heat transfer analysis in sub-channels of rod bundle geometry with supercritical water