Distributed Pressure Sensing for Production Data Analysis

ABSTRACT: The carbonate formations are characterized by developing continuous grid-like fractured structures, which pose a great challenge on effective hydraulic fracturing. In order to investigate the fracture propagation behavior in such grid-like fracture carbonate reservoirs and the interaction between hydraulic fracture and grid-like fracture, we employed a Unconventional Fracture Model (UFM) based on the boundary element approach in this paper to simulate the fracturing process in fractured carbonate reservoirs. The effects of key geological and engineering parameters such as fracture approach angle, pump displacement, and stress difference on stimulated reservoir volume were analyzed, and well trajectories were also optimized. Under the condition of Shunbei carbonate reservoir, when the angle α between the grid-like fracture and the horizontal well is 90°, the hydraulic fracture tends to extend parallel to the direction of the grid-like fracture, when α is 45°, the hydraulic fracture tends to penetrate the grid-like fracture and then propagate along the maximum principal stress, and when α is less than 45°, the hydraulic fracture tends to penetrate the grid-like fracture and then be captured by the natural fracture. In the Shunbei reservoirs, with a local stress difference of 40 MPa, the optimal pump displacement is 4∼6 m3/min. 1. INTRODUCITON Marine carbonate reservoirs are rich for oil and gas resources. In world's proven oil and gas reserves, 60% in the marine carbonate reservoirs, that has become a key area of oil and gas exploitation. Among the marine carbonate reservoirs, grid-like fractured reservoirs is a special structure. Marine carbonate reservoirs are stretched and shear by geological processes, forming deep faults and grid-like fractured zones, that are grid-like fractured reservoirs. Which generally exist in ultra-deep, high-temperature and high-pressure geologic environments, and have received focused attention in recent years (Wang W et al., 2023; LI Y et al., 2022). Currently, hydraulic fracturing is the main means for exploiting grid-like fracture reservoirs. However, hydraulic fracturing communication large grid-like fractures and many natural fractures has limited, and the classical theory of fracture propagation is not applicable (Hui G et al., 2023). Therefore, to study the propagation law of hydraulic fracture in grid-like fracture reservoirs is important. So far, many scholars have conducted a lot of research on the interaction between hydraulic fracture and grid-like fracture (Zhang Q et al., 2021). However, fracture propagation in grid-like fracture Still have not theoretical support, and the mechanism of hydraulic fracture propagation in grid-like fractured reservoirs is not clear. Based on the UFM model and with the help of Kinetix (Kresse O et al., 2013), which is an integrated software platform for geo-engineering. The authors modeled the grid-like fractured reservoirs, and studied the propagation of hydraulic fracture under the condition of grid-like fracture medium (Ma D C et al., 2023).

Summary Hydraulic fractures can enhance well productivity from stress-sensitive naturally fractured reservoirs, such as coalbed methane or coal seam gas (CSG) reservoirs. Graded proppant injection (GPI) has been proposed to enhance long-term, far-field interconnectivity between the created hydraulic and short-term, enhanced natural fracture permeability, resulting from fracture fluid leakoff and lowered net effective stress. This novel study shows how applying GPI with hydraulic fracturing treatments resulting in an increased stimulated reservoir volume (SRV) can enhance well productivity and improve CSG well economics. A commercially available reservoir model and history-matched hydraulically fractured coal seam case are used to evaluate well performance differences between a hydraulic fractured reservoir and one including GPI application. A dual-porosity system and the Palmer and Mansoori model are used to simulate initial and long-term permeability accounting for reservoir depletion (i.e., increased net effective stress and matrix shrinkage). A previously validated case study is used to describe the post-embedment benefits of GPI based on the porosity model and history-matched reservoir properties. A net present value (NPV) can then be calculated for each scenario, based on the production differences and typical Australian CSG costs. Our results show that permeability enhancement is achieved beyond the hydraulically fractured region for all post-GPI stimulation cases. An optimal SRV can be found relative to permeability that maximizes the incremental NPV from GPI application. The next most significant parameters after permeability that influence the economic outcomes are fracture porosity and coal compressibility. A larger SRV yields higher cumulative gas production over 30 years with up to 7.2 times increase over gas production without GPI. This study substantially increases our understanding of how to model and understand the benefits of GPI application along with hydraulic fracturing to increase the SRV in CSG wells.

This work presents new solutions to modeling the production performance of hydraulically fractured wells in unconventional reservoirs, where intensive hydraulic fracturing creates a stimulated reservoir volume (SRV) with an induced permeability field within.We found previously that the permeability field induced in the SRV (single porosity) can be effectively represented by an exponential or linear dependence of permeability on the distance measured from the main hydraulic fracture plane. However, many researchers consider dual porosity as a necessary ingredient in modeling unconventional reservoirs.In this work, we extend the induced permeability field model to the dual porosity idealization, considering transient fluid transfer from matrix to natural fractures and distance-dependent properties of the medium of secondary porosity (affected by the intensive stimulation).We show that the combined effect of creating a main fracture and altering the properties of the medium of secondary porosity leads to a production behavior that can be characterized and understood provided that effects related to skin and varying flowing bottomhole pressure are correctly accounted for.In addition to the standard diagnostic tools for decline-curve or rate-transient analysis, we use the ratio between the production time and material balance time, a dimensionless group that enables identifying the characteristic signatures of flow regimes. We provide practical criteria to identify various scenarios affecting the data during the pre-linear and prebilinear flow regimes in the reservoir (short times). Then we show that transient, late transient and boundary dominated flow periods can also be diagnosed using the dimensionless group, providing a useful addition to existing procedures involving conventional plots.In connection to the new model, this work also discusses a novel approach to handle non-constant bottomhole pressure, the cause of significant distortion in production data at early times. In particular, we consider the effect of a bottomhole pressure exponentially approaching a stabilized value. We show that the deviation from the idealized constant bottomhole pressure case depends on the flow regime in the reservoir, fluid and reservoir properties, skin factor, and the mean lifetime (the time when 63% of the total change has happened) of the decaying part of the flowing pressure. The results reveal that half-, three-fourths-, and unit-slope straight lines (on log-log plot of production rate versus time) develop at short times during the increasing trend of production rate. These new flow regimes enable to gain useful information about the SRV from the early stage of the production history – if the quality of data allows such a detailed analysis.We present a field example involving multi-fractured horizontal wells producing from a shale-gas reservoir, to illustrate, in a practical manner, how to apply the new approach when interpreting production history of wells in unconventional reservoirs.

Accurate modeling of hydrocarbon production is a necessary, yet challenging step for economic exploitation of unconventional resources. One of the main challenges is to model flow to a horizontal well from a complex network of hydraulic and natural fractures. Many unconventional reservoirs comprise well-developed natural fracture networks with multiple orientations and complex hydraulic fracture patterns based on microseismic data. Conventional dual porosity and dual permeability models are not adequate for modeling these complex networks of natural and hydraulic fractures. Also, it is neither practical nor advantageous to model a large number of pre-existing fractures with a discrete fracture model. Therefore, an appropriate approach to model production from low-permeability reservoirs is to perform discrete fracture modeling for hydraulic fractures and employ a dual continuum approach for numerous natural fractures. We have developed a coupled dual continuum and discrete fracture method to simulate production from unconventional oil and gas reservoirs. Large-scale hydraulic fractures (macro-fractures) are modeled explicitly using a discrete fracture model, called EDFM, and numerous small-scale natural fractures (micro-fractures) are modeled using a dual continuum approach. The hybrid model includes three domains: matrix, discrete-fracture, and continuum-fracture domains. A systematic approach is devised to calculate transport parameters between all three domains. Moreover, EDFM allows for not only transverse and longitudinal hydraulic fractures but also macro-fractures of any orientation. Thus, the coupled model provides an effective and reliable environment to improve stimulation designs and completion strategies. We present several examples in this study to show the applicability, robustness, and performance of the hybrid method for the simulation of unconventional oil and gas reservoirs. We examine multi-stage hydraulic fractures with multiple configurations in the presence of numerous pre-existing fractures. Simulations show a noticeable contribution from natural fracture networks on total production. Furthermore, for the tight oil reservoir examined in this study, the stimulation scheme with longer hydraulic fractures improves cumulative oil production compared to the scheme with larger number of shorter hydraulic fractures. We also examine production from a tight gas reservoir wherein hydraulic fractures partially penetrate the formation height. Simulations indicate that inefficient fracture treatment can result in significant loss of production.

We investigate the rate-transient behavior of multistage fractured horizontal wells in conventional and unconventional homogeneous and naturally fractured reservoirs, the latter of which can contain any spatial distribution of finite- or infinite-conductivity fractures of arbitrary length and orientation. The number and type of fractures (hydraulic or natural) intersecting the wellbore and self-intersecting is unlimited. We show that there are many factors that dominate the ratetransient behavior of horizontal wells intersected by multiple hydraulic fractures in naturally fractured reservoirs, such as fracture conductivity, length, and distribution, as well as whether or not fractures intersect the wellbore. It is shown that the magnitude of the fracture conductivity is one of the most important parameters that affects the production performance of multistage fractured horizontal wells. It is also shown that, as the space increases between hydraulic and natural fractures intersecting a horizontal well, the fracture pseudosteady-state flow regime tends to disappear. Using the pressure and flow rate equivalency principle, we show that a production rate and/or cumulative production data set can be transformed into an equivalent pressure or pressure derivative data set. This is also very important for unconventional gas and oil reservoirs, where the boundary-dominated pseudosteady-state flow regime takes years to develop. A new technique is presented for determining stimulated reservoir volume (SRV) and production forecasting. It is shown that rate derivatives exhibit unusual behavior, from which system identification and flow regime analysis become impossible. The material balance time does not totally correct the unusual behavior of the rate derivative. However, the deconvolved pressure of the cumulative production derivatives behave like pressure derivatives.

Recent success of commercial shale gas developments in a number of basins throughout North America can be attributed to the application of advanced technologies used to drill horizontal wellbores, stimulate the shale reservoir, and optimize productivity of shale-bearing formations. Many of the drilling and completion techniques learned from the thousands of wells drilled and stimulated in more mature shale basins, such as the Barnett, have been applied to newer shale discoveries such as the Marcellus and Haynesville in the United States, and both the Montney and the remarkable Horn River Basin in Canada. The unique properties of each shale, however, preclude a "cookie-cutter" development approach from being applied. Each play must be optimized as a unique reservoir. In order to utilize numerical simulation as a tool in optimizing well design, one needs to develop a model that appropriately represents the complex process of gas flow from the native reservoir to the hydraulic fractures and subsequently to the wellbore. This is challenging due to poor understanding of variables such as pressure dependent permeability variation, fluid cleanup, relative permeability effects, non-Darcy flow, methane desorption in a nano-Darcy shale matrix, and fracture conductivity variations from the dominant hydraulic fractures to the secondary induced and natural fractures. Another challenge is accurate representation of the hydraulic fracture. Is the fracture planar or complex? What is the fracture geometry? What is the fracture intensity within the stimulated volume? What is effectively propped? What is the proppant distribution within the fracture system? How does this tie to effective conductivity and does it vary with distance from the wellbore (three dimensionally)? Finding a unique match to historical production is very challenging. Shale gas operators collect a large amount of data including cores and logs (specialized for nano-Darcy rock), micro seismic, diagnostic fracture injection testing (DFIT), fluid and proppant tracers and more. This data is used to better characterize the reservoir and the natural and hydraulic fractures and can help to constrain model inputs. This paper discusses a workflow used in developing a numerical shale gas model for Nexen’s Horn River shale gas reservoir. Presented is a practical and systematic approach to using surveillance data; specifically microseismic data in construction of the stimulated reservoir volume (SRV) and the network of hydraulic fractures in the model. Discussions will also focus on accurately modeling complexities such as non-Darcy flow in the hydraulic fractures, pressure-permeability dependencies, variations in hydraulic fracture conductivity and fluid cleanup. The objective is to gain understanding and insight into the uncertainties that have the greatest impact on well performance.

The stimulated reservoir volume (SRV) estimated from daily production rate and pressure is a vital parameter for appraising shale gas wells’ fracturing effect and production potential. However, when well interference occurs, the SRV estimation from rate-normalized pressure (RNP) analysis is compromised. This paper illustrates diagnosis of well interference and how it affects SRV calculation. China is the third country to exploit the shale gas technology breakthrough after the United States and Canada. The Jiaoshiba shale gas play is the most successful shale gas reservoir in China with some wells’ cumulative production over 0.1 billion cubic meters in the first year. Production rate data has shown jumps in water production during hydraulic fracturing of neighboring wells. By combination of hydraulic fracturing process and production data, we detect the existence of well interference from the adjacent well, when well interference happens and the influence it imposed on the target well. We analyzed two pairs of target and neighboring shale gas well pairs using the RNP and its derivative. The log-log diagnostic plots for nearly all of the wells see unit slope, indicating boundary dominated flow within 1 year. Some wells see two unit slopes possibly indicating a change in the SRV after hydraulic fracturing in a neighboring well. Well interference may be caused by interaction between primary hydraulic fractures and/or secondary natural fractures activated during hydraulic fracturing. Interwell interference has had a significant influence on the SRV interpretation. Well interference has drawn people's attention in recent years, but its impact on SRV interpretation is rarely reported. This research may help to characterize shale gas's SRV and related parameters and to optimize well spacing.

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.

Hydraulic fracturing in shale formations containing natural fractures can lead to complex and branched fracture networks which may fail to efficiently access hydrocarbons deep in the formation away from the well. In this study, to minimise the negative effects of natural fractures, the orientation of hydraulically fractured wells in such formations is investigated with the focus on the effects of in-situ differential stresses and toughness of natural fractures. To explore the impact of geomechanical properties on gas production from hydraulically fractured wells, fractures were first up scaled and then gas production from the reservoir was investigated. The results show that low natural fracture toughness and differential in-situ stress both increase the tendency of propagating hydraulic fractures to exploit natural fractures. Under these conditions, it was found that drilling the well in a modified orientation could result in a higher recovery factor compared to the wells drilled parallel to the direction of minimum horizontal stress. This is due to the larger stimulated reservoir volume through a synergy between the hydraulic and natural fractures. However, high differential in-situ stress and fracture toughness both lead to a transition from this tendency, in which hydraulic fractures cross natural fractures rather than exploiting them. As a result, changing the well orientation in these scenarios are less efficient than the industry standard. The results of this study demonstrate a window of geomechanical scenarios in which changing well orientation is beneficial, can be produced as a fast-screening method for engineers to determine the optimised well orientation.

Summary Economic production from shale-gas reservoirs typically relies on the drilling of horizontal wells and hydraulic fracturing in multiple stages. In addition to the creation of hydraulic fractures, hydraulic-fracturing treatment can also reopen existing natural fractures, which can create a complex-fracture network. The area that is covered by the fracture network is usually termed the stimulated reservoir volume (SRV), and the spatial extent and properties of the SRV are crucial for shale-gas-production behavior. In this work, we propose a method for history matching of the SRV of shale-gas reservoirs using production data. For each hydraulic-fracturing stage, the fracture network is parameterized with one major fracture of the hydraulic fractures and the SRV that represents minor hydraulic fractures and reopened natural fractures. The major fracture is modeled explicitly, whereas the SRV is modeled by the dual-permeability/dual-porosity (DP/DP) model. Moreover, the spatial extent of the SRV is parameterized by the level-set-function values on a predefined representing-node system. After parameterization, an iterative ensemble smoother is used to perform history matching. Both single-stage-fracturing cases and multistage-fracturing cases are set up to test the performance of the proposed method. Numerical results demonstrate that by use of the proposed method, the SRV can be well-recognized by assimilating production data.

Researchers have recently realized that the natural fractures in shale reservoirs are often cemented or sealed with various minerals. However, the influence of cement characteristics of natural fracture on fracturing network propagation is still not well understood. In this work, laboratory-scaled experiments are proposed to prepare model blocks with discrete orthogonal fractures network with different strength of natural fracture, in order to reveal the influence of cemented natural fractures on the interactions between hydraulic fractures and natural fractures. A series of true triaxial hydraulic fracturing experiments were conducted to investigate the mechanism of hydraulic fracture initiation and propagation in model blocks with natural fractures of different cement strength. The results present different responses of interactions between hydraulic and natural fractures, which can be reflected on the pump pressure profiles and block failure morphology. For model blocks with fluctuated pump pressure curves, the communication degree of hydraulic and natural fractures is good, which is confirmed by a proposed new index of “P-SRV.” The most significant finding is that too high and too low strength properties of cemented natural fracture are adverse to generate complex fracturing network. This work can help us better understand how cemented natural fractures affect the fracturing network propagation subsurface and give us reference to develop more accurate hydraulic fracturing models.

ABSTRACT: Hydraulic fracture trajectory near the wellbore directly influences the efficiency of fluid flow into and out of the well. Modeling the near-wellbore hydraulic fracture behaviors has been challenging due to the combined impacts of wellbore perforation placement, stress concentration around the wellbore and perforation tunnels, in-situ stress conditions, as well as pre-existing fractures in the subsurface that interact with hydraulic fractures. In this paper, we have built numerical models to take into account the aforementioned factors and investigate near-wellbore fracture growth and fluid pressure characteristics. The numerical models use a distinct element method (DEM) approach that explicitly represents the well casing, cement sheath, and perforation tunnels, with natural fractures represented by Smooth Joint Model. The results show that natural fractures intersecting the perforation tunnels at a favorable angle with respect to in-situ stress directions can facilitate fracture initiation in hard rocks. Multiple initiation points may occur, while one fracture becomes dominant at a later time in the simulated case. In addition, the simulation results show the termination of hydraulic fracture growth in the highly fractured zone, as well as hydraulic fractures crossing natural fractures that have small effective sizes at the interaction location. This study also demonstrates the efficacy of the near-wellbore model to represent detailed wellbore elements, consider complex discrete fracture networks, and capture the fundamental mechanisms that influence near-wellbore hydraulic fracture behaviors. 1. INTRODUCTION The trajectory of hydraulic fractures near the wellbore directly influences the efficiency of fluid flow into and out of the well, making it a crucial factor that can impact several critical aspects in unconventional reservoirs and enhanced geothermal systems, such as reservoir connectivity, fluid circulation, proppant transportation, and energy production efficiency. Modeling near-wellbore fracture initiation and propagation has been challenging due to complex influencing factors that need to be considered, including the casing-cement sheath-perforation tunnel-rock structure, stress concentrations resulting from the wellbore and perforation tunnels, interference, competition, and merging of hydraulic fractures, interactions within the hydraulic discrete fracture network, and in-situ stress conditions. A model must span multiple scales to accurately capture different fracture behaviors, from fracture initiation along perforation tunnels at a millimeter scale to fracture propagation near the wellbore at a meter scale. In this study, a numerical model was established to investigate hydraulic fracture behaviors in the near-wellbore region. Utilizing a distinct element method (DEM) lattice approach, we analyzed hydraulic fracture initiation and propagation behaviors under the combined impacts of wellbore perforation and discrete fracture network (DFN). The model is based on hydraulic fracturing tests conducted at the Utah FORGE Site. Well casing, cement sheath, and perforation tunnels were explicitly represented in the simulation, and fluid pressure characteristics and corresponding fracture behaviors are discussed in detail.

Optimization of horizontal well fracturing in shale gas reservoir based on stimulated reservoir volume

Integrated analysis of pressure response using pressure-rate convolution and deconvolution techniques for varied flow rate production in fractured formations

본 연구에서는 보다 현실적인 파쇄균열 전파를 묘사하기 위해 수압파쇄균열 전파 모델을 개발하였다. 이 모델에서는 두 가지 균열 전파 기준을 적용하였다. 첫 번째는 균열의 발생각을 결정하기 위한 최대 접선응력 기준과 두 번째는 파쇄균열의 자연균열 통과 여부 기준이다. 본 모델의 검증 결과, 수압파쇄균열이 자연균열을 통과하는 양상이 실험값과 동일함을 확인하였다. 균열의 전파에 직접적인 영향을 미치는 요소인 최대수평응력 방향, 균열면의 마찰계수, 자연균열의 방향성에 대한 민감도 분석 결과, 이론적 기준에 적합하게 균열의 전파 방향과 통과 여부가 결정되는 것으로 나타났다. 기존의 수직 판형 균열 전파 모델과 본 모델을 비교하여 균열의 연결성과 유정 자극부피 측면에서 차이가 있음을 확인하였다. This paper presents a hydraulic fracture propagation model to describe propagation more realistically. In propagating the hydraulic fractures, we have used two criteria: maximum tangential stress to determine the fracture initiation angle and whether a hydraulic fracture intersects a natural fracture. The model was validated for the parameters relevant to fracture propagation, such as initiation angle and crossing ability through natural fracture. In order to check whether a hydraulic fracture crosses a natural fracture, the model results on crossing state excellently matched with the experimental data. In the sensitivity analysis for direction of maximum horizontal stress, frictional coefficient of fracture interface, and natural fracture orientation, the results show that hydraulic fracture intersects natural fracture, and then, propagated suitably with theoretical results according to fracture interaction criterion. In comparison of this model against vertical fracture approach, it was ascertained that there are discrepancies in fracture connectivity and stimulated reservoir volume.