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Abstract Casing Deformation has presented itself in numerous unconventional basins. Severe deformation interferes with multistage fracturing, in particular with plug-and-perforation (also known as plug-and-perf) operations, the most common stage isolation method in unconventional development. Casing Deformation can greatly impact 20-30% of field productivity of horizontal wells in certain US shale and tight oil fields (Jacobs, 2020). Reservoir accessibility and well integrity are the two separate issues when considering casing deformation. In this paper, the impact of geomechanically driven casing deformation on reservoir accessibility that in turn affects production and economics, will be discussed. Origin of casing deformation within a target zone lies in natural fractures placed in highly anisotropic stress regimes. When these fractures are perturbed by hydraulic stimulation, slow slip or dynamic failure of the rock may occur. This phenomenon is intensified by active tectonics, high anisotropic in-situ stresses, and poor completion practices, i.e., poor cement. This paper evaluates these processes by demonstrating failure conditions of wellbores in different stress states and well orientations representative of unconventional basins. It reviews how these conditions can be evaluated in the reservoir, so risk can be estimated. The mitigation procedures to reduce casing deformation impact to operations through either well planning or completions design are discussed. Finally, this paper will also review an alternative completion method to plug-and-perf that allows limited entry completion technique in restricted ID casing due to casing deformation with a field case study.
Abstract Diagnostic fracture injection tests (DFIT) are used as an indirect method to determine closure pressure and formation effective permeability in unconventional reservoirs as a first step in formation evaluation. The information obtained from DFIT is particularly useful because it is obtained before any production for a given well is available. In DFIT, a small fracture is created by injecting few barrels of completion fluid until formation breaks down and a fracture is initiated and propagates a short distance into the reservoir. Then, injection is stopped, and the pressure decline (or falloff) is monitored. From this pressure decline, the effective permeability of the formation is estimated by Nolte's G-function, log-log plot, or square root of time analysis. In this research, the viability of the common DFIT analysis techniques was investigated for unconventional reservoirs with and without micro-fractures by using a numerical hydraulic fracturing simulator, CFRAC. The results of numerical simulations were investigated to assess the impact of permeability, residual fracture aperture, and complex fracture networks on conventional DFIT interpretations. For the example considered in this work, the commonly used G-function analysis yielded estimates of permeability over an order of magnitude higher than the simulated matrix permeability. Error in the G-function estimates of permeability were higher for higher matrix permeability and in the existence of a fracture network. On the other hand, straight-line analysis of Ap versus G-time yielded much closer (in the same order of magnitude) estimates of permeability.
In Shale and Tight, the term "Parent-Child effect" refers to the impact the depleted area and corresponding stress changes originated by the production of a previously drilled well, the "parent", has over the generated hydraulic fracture geometry, conforming initial drainage area and consequent production performance of a new neighbor well, called "child". Such effect might be considered analogous to the no flow boundary created when the drainage areas of two wells meet at a certain distance from them in conventional reservoirs; but, unconventional developments exhibit higher exposure to a more impactful version of this phenomena, given their characteristic tighter well spacing and the effect pressure depletion of the nearby area by the neighbor well has over the child well's hydraulic fracture development. Due to the importance the Parent-Child effect has for unconventional developments, this study aims first to generally characterize this effect and then quantify its expected specific project impact based on real field data from the Vaca Muerta formation. To do so, we developed a methodology where fracture and reservoir simulation were applied for calibrating a base model using field observed data such as microseismic, tracers, daily production data and well head pressure measurements. The calibrated model was then coupled with a geomechanical reservoir simulator and used to predict pressure and stress tensor profiles across different depletion times. On these different resulting scenarios, child wells were hydraulically fractured with varying well spacing and completion designs. Finally, the Expected Ultimate Recovery (EUR) impact versus well spacing and the parent s production time were built for different child s completion design alternatives, analyzed and contrasted against previously field observed data. Results obtained from the characterization work suggests the parent child effect is generated by a combination of initial drainage area changes and stress magnitude and direction changes, which are both dependent of the pressure depletion from the parent well. Furthermore, the results show how the well spacing and parent's production timing, as well as parent's and child's completion design, significantly affect the magnitude of the expected parent child effect impact over the child's EUR. 2 SPE-206001-MS
Abstract Infill completions have been explored by many operators in the last few years as a strategy to increase ultimate recovery from unconventional shale oil reservoirs. The stimulation of infill wells often causes pressure increases, known as fracture-driven interactions (FDIs), in nearby wells. Studies have generally focused on the propagation of fractures from infill wells and pressure changes in treatment wells rather than observation wells. Meanwhile, studies regarding the pressure response in the observation (parent) wells are mainly limited to field observations and conjecture. In this study, we provide a partialcorrective to this gap in the research.We model the pressure fluctuations in parent wells induced by fracking infill wells and provide insight into how field operators can use the pressure data from nearby wells to identify different forms of FDI, including fracture hit (frac-hit) and fracture shadowing. First,we model the trajectory of a fracture propagating from an infill well using the extended finite element methods (XFEM). This method allows us to incorporatethe possible intersection of fractures independent of the mesh gridding. Subsequently, we calculate the pressure response from the frac-hit and stress shadowing using a coupled geomechanics and multi-phase fluid flow model. Through numerical examples, we assess different scenarios that might arise because of the interactions between new fractures and old depleted fractures based on the corresponding pressure behavior in the parent wells. Typically, a large increase in bottomhole pressure over a short period is interpreted as a potential indication of a fracture hit. However, we show that a slower increase in bottomhole pressure may also imply a fracture hit, especially if gas repressurization was performed before the infill well was fracked. Ultimately, we find that well storage may buffer the sudden increase in pressure due to the frac-hit. We conclude by summarizing the different FDIs through their pressure footprints.
Brednev, Philipp (Gazpromneft STC) | Elesin, Mikhail (Gazpromneft STC) | Berezovskiy, Yuri (Gazpromneft STC) | Metelkin, Denis (Gazpromneft GEO) | Volkov, Georgy (Gazpromneft GEO) | Firsin, Maksim (Gazpromneft NNG) | Mukminov, Iskander (Gazpromneft GEO)
This article deals with the issues related to development of petroleum resources of Western Siberia and looks at one of the most promising development targets - reservoirs of the Achimov Formation. In particular, it discusses geological features of the Achimov rocks, and the difficulties faced by oil companies in development of the Achimov reservoirs due to their low economic viability if traditional approaches to well construction are applied. To make development of such reservoirs economical, new and non-trivial solutions need to be looked for. One of the most promising of them is considered to be multi-hole wells the construction of which allows oil companies to improve the Capex to cumulative production ratio. At the pre-FEED stage the project, geological, hydrodynamic and geomechanical models of the reservoir were built, the most efficient borehole parameters and trajectories were defined, and the optimal hydraulic frac design, number of stages and parameters were selected. The article describes specifics of the work carried out when preparing for pilot tests of the technology, such as: a. requirements for defining the well profile and selecting the optimal lifting capacity of the drilling rig, b. selection of a suitable complexity level for the double-hole well design among those considered which meets the drilling requirements, c. performance of bench tests to confirm operability of the TAML-3 equipment. Further, the article describes results of drilling, completing and commissioning the first double-hole well at the Vyngayakhskoye field, discusses the issues faced when using the completion equipment at the TAML-3 level, and the lessons learned from this project. It also presents results of putting the double-hole well on-stream and compares its production characteristics with those of single-hole horizontal wells drilled within the same well cluster. The experience gained has shown that building the discussed type of wells is technically feasible, and there is a wide potential for improving efficiency of this work through respective organizational and technical measures.
Abstract Diagnostic fracture injection tests (DFIT) are used widely in the unconventional reservoirs to obtain formation properties. These properties can be crucial in optimizing primary and infill completions. The interpretation methods are assuming that pumping fluid would create a single planar fracture, however, perforation frictions and near wellbore stress concentration may accommodate initiation of fractures along the casing first (axial fractures). The possibility of the formation of an axial fracture increases in high injection rates and low differential stresses. In this study, we investigate the effect of the formation of an additional axial fracture on a DFIT test and its interpretation, using a fully coupled geomechanics and fluid flow model. We provide a model for the initiation and closure of axial and transverse fractures during the process. We also demonstrate that the estimate of the closure stress can be misleading when presence of an additional axial fracture is ignored. Finally, we discuss a potential method to determine the maximum horizontal stress under such circumstances. In fact, the variations in cement quality, cement type and its placement play roles in linking of adjacent perforations and form axial fractures, therefore it might be difficult to establish a safe perforation design to avoid initiation of axial fractures, but we can adjust our analysis to incorporate axial fractures effect.
Abstract The change of fracture conductivity during reservoir depletion significantly affects the well performance and stress evolution in unconventional formations. A common practice is to model fracture deformation using the traditional finite element method with very dense unstructured grids representing complex fracture geometries. However, the associated computational cost is high, so previous studies mainly use empirical correlations to catch the fracture conductivity loss or neglect fracture deformation during the production period. This work proposes a novel coupled flow and geomechanics model with embedded fracture methods to capture the fracture deformation accurately yet efficiently in unconventional reservoirs. Under a single set of structured grids, an embedded discrete fracture model (EDFM) is employed to characterize fluid flow through discrete fractures by introducing non-neighboring connections, and an extended finite element method (XFEM) is applied to simulate discontinuities over fracture walls by adding phantom nodes. In addition, a modified proppant model is incorporated to represent interactions between proppants and hydraulic surfaces, and an iterative coupling scheme is implemented to link the fracture-related fluid flow and solid mechanics. Being validated against the classical benchmark problem, the coupled model is used to investigate the impacts of proppant strength, closure stress, and bottomhole pressure on fracture deformation, well production, and in-situ stresses. Numerical results indicate that weaker proppant support induces more fracture aperture and production losses, resulting in greater stress changes and higher residual pressure in the depletion region. In comparison, the fracture deformation for a well-propped scenario is modest and barely affects the well performance and stress redistribution. Less stressed formation corresponds to lower closure stress on fracture walls, which triggers limited fracture closure and stabilizes well production. Moreover, a moderate bottomhole pressure decline rate avoids significant fracture closure while preserves relatively high initial production rates. The coupled flow and geomechanics model with embedded fracture methods resolves computational difficulties in modeling complex fracture deformations and delivers more insights on production forecast and stress changes crucial to refracturing and infill operations.
Hussain, Maaruf (Baker Hughes) | Amao, Abduljamiu (King Fahd University of Petroleum and Minerals) | Al-Ramadan, Khalid (King Fahd University of Petroleum and Minerals) | Olatunji, Sunday (Imam Abdulrahman Bin Faisal University) | Negara, Ardiansyah (Baker Hughes)
Abstract The knowledge of rock mechanical properties is critical to reducing drilling risk and maximizing well and reservoir productivity. Rock chemical composition, their spatial distribution, and porosity significantly influenced these properties. However, low porosity characterized unconventional reservoirs as such, geochemical properties considerably control their mechanical behavior. In this study, we used chemostratigraphy as a correlation tool to separate strata in highly homogenous formations where other traditional stratigraphic methods failed. In addition, we integrated the chemofacies output and reduced Young's modulus to outline predictable associations between facies and mechanical properties. Thus, providing better understanding of lithofacies-controlled changes in rock strength that are useful inputs for geomechanical models and completions stimulations.
Abstract This paper presents an analysis of the stimulation treatment design and the optimization of the stimulation treatments in the challenging ultra-HPHT environment (400°F and 15000psi) of the Krishna-Godavari (KG) basin, East Coast, India. In greater detail, the paper focuses on how the perforation placement and the stimulation treatment design have been optimized for each zone of a multi-zone treatment program in a deviated well to address the specific challenges (geological, completion, operational and logistical) associated with the environment. An in-depth analysis was performed on the stimulation design prior to mobilization of stimulation equipment and crew. The treatments were designed by utilizing as inputs tailored petrophysical and geomechanical models, well design data, stimulation material properties and equipment capacities, and analysis of prior stimulation experience in this area. Extensive sensitivity analysis was carried out to come up with the optimum perforation depths and stimulation treatment. Subsequently, when on location, the treatment design was fine-tuned using real-time data to optimally place the fracture. The overall goal was to determine the best stimulation treatment for the offshore well without inducing negatively impacting either the reservoir production or ultimate recovery. From adherence to fundamentals of well and frac design to completion optimization, major efforts were made in the treatment optimization for each zone based on the challenges associated with the KG basin. These challenges, in no particular order, include high temperature and high pressure, proximity to water zones and the necessity to isolate treatment stages using unconventional methods, presence of high fluid loss zones, and logistical/space constraints inherent from the offshore location. Stimulation treatments implemented in this field in the past were analyzed to better understand the pros and cons of the various stimulation techniques and practices that were employed. A key learning from this exercise was that the stimulation fluid selection is of utmost importance. With a BHST of 400°F, stimulation fluids that can provide adequate stability under these conditions are limited. This led to an increased focus on the engineering design of stimulation treatments in the pre-planning phase, which was then optimized as real-time data was acquired. Wellbore re-entry issues led to further re-evaluation and redesign of the perforation strategy. Improvements in treatment sizing were made during the stimulation as water zones needed to be avoided or stress conditions needed to be corrected from early design conditions assumed. Furthermore, upon completion of each stimulation stage, proper and unconventional isolation methods were needed from earlier stimulation due to tubular limitations. Post-frac evaluation using hydraulic fracture pressure match indicated that 3 out of the 5 zones were stimulated with highly conductive and long fractures, while minimal size treatments were placed in 2 troublesome zones. Also, treating a high-risk water zone was avoided. In conclusion, the authors believe that the stimulation program was optimally designed and conducted in an area with limited success in years past by using sound engineering in all the phases of the design and implementation.
Marketz, Franz (Sakhalin Energy Investment Company Ltd.) | Brown, David (Sakhalin Energy Investment Company Ltd.) | Alyabiev, Roman (Sakhalin Energy Investment Company Ltd.) | Khudorozhkov, Pavel (AKROS LLC.) | Sychov, Oleg (AKROS LLC.)
Abstract The cuttings re-injection (CRI) well in the Astokh area of Piltun-Astokhskoye field offshore Sakhalin Russia is one of the longest operating drilling waste disposal wells in the oil and gas industry worldwide. The Astokh area has been developed as a waterflood and is operated by Sakhalin Energy, a joint venture between Gazprom, Shell, Mitsui, and Mitsubishi. The Astokh CRI well has been utilized for waste injection for over 16 years. About 300,000 m3 of waste has been disposed into the main injection zone of the CRI well. Monitoring and modelling the CRI process to understand the evolution of the disposal domain is paramount for safeguarding further disposal operations. The disposal domain can be described as a complex system of multiple hydraulic and natural fractures due to injection under fracturing conditions. CRI domain evaluation includes analysis of historical injection pressures to identify the reasons of continuous injection pressure increase with increasing cumulative waste volumes disposed, to confirm domain containment, and to predict remaining domain capacity. Transient pressure analysis has revealed that the fracture closure pressure, driven by pore pressure increase and the accumulation of injected solid-phase waste, is the key parameter affecting injection pressures. Injection intensity, periods of shut-in, large overflushes, and solids-free liquids injections with corresponding solids and stresses redistribution are the other factors that affecting the pressure trends. CRI domain mapping was carried out with history-matched time-lapse 3D hydraulic fracture models. Injection pressure history matching results reveal the fracture geometry evolution during well life. The distribution of the injected liquid phase in the sand layers was modeled with a 3D dynamic reservoir sector model, matched with injection pressures and with formation pressure data in two offset wells, located at a distance of 1 and 2 kilometers, respectively. A matched model was then used to assure fracture containment for future waste disposal and to estimate remaining domain capacity. High-precision temperature and spectral noise logs were acquired in seawater injection and shut-in modes. The log-derived fracture height confirmed the domain size predicted by the matched model. 4D seismic data processing revealed that dimensions of Geomechanically Altered Rock Volume (GARV) were also in the same range as predicted by the model p. The integration of CRI domain evaluation with matched 3D hydraulic fracture models, well logs and 4D seismic demonstrated that injection pressure data collected during every injection cycle may be sufficient to characterize disposal domain evolution and to estimate domain capacity.