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Producing formation damage has been defined as the impairment of the unseen by the inevitable, causing an unknown reduction in the unquantifiable. In a different context, formation damage is defined as the impairment to reservoir (reduced production) caused by wellbore fluids used during drilling/completion and workover operations. It is a zone of reduced permeability within the vicinity of the wellbore (skin) as a result of foreign-fluid invasion into the reservoir rock. Typically, any unintended impedance to the flow of fluids into or out of a wellbore is referred to as formation damage. This broad definition includes flow restrictions caused by a reduction in permeability in the near-wellbore region, changes in relative permeability to the hydrocarbon phase, and unintended flow restrictions in the completion itself. Flow restrictions in the tubing or those imposed by the well partially penetrating a reservoir or other aspects of the completion geometry are not included in this definition because, although they may impede flow, they either have been put in place by design to serve a specific purpose or do not show up in typical measures of formation damage such as skin.
Formation damage caused by drilling-fluid invasion, production, or injection can lead to positive skin factors and affect fluid flow by reducing permeability. When mud filtrate invades the formation surrounding a borehole, it will generally remain in the formation even after the well is cased and perforated. This mud filtrate in the formation reduces the effective permeability to hydrocarbons near the wellbore. It may also cause clays in the formation to swell, reducing the absolute permeability of the formation. In addition, solid particles from the mud may enter the formation and reduce permeability at the formation face.
If the problem is formation damage, then matrix acidizing may be an appropriate treatment to restore production. This page discusses ways to evaluate whether a well is a good candidate for acidizing. This plugging can be either mechanical or chemical. Mechanical plugging is caused by either introduction of suspended solids in a completion or workover fluid, or dispersion of in-situ fines by incompatible fluids and/or high interstitial velocities. Chemical plugging is caused by mixing incompatible fluids that precipitate solids.
This article discusses the basic concepts of single-component or constant-composition, single phase fluid flow in homogeneous petroleum reservoirs, which include flow equations for unsteady-state, pseudosteady-state, and steady-state flow of fluids. Various flow geometries are treated, including radial, linear, and spherical flow. Virtually no important applications of fluid flow in permeable media involve single component, single phase 1D, radial or spherical flow in homogeneous systems (multiple phases are almost always involved, which also leads to multidimensional requirements). The applications given in this Chapter are based on a model that includes many simplifying assumptions about the well and reservoir, and are interesting mainly only from a historical perspective See "Reservoir Simulation" for proper treatment of multi-component, multiphase, multidimensional flow in heterogeneous porous media. The simplifying assumptions are introduced here as needed to combine the law of conservation of mass, Darcy's law, and equations of state to obtain closed-form solutions for simple cases. Consider radial flow toward a well in a circular reservoir. Combining the law of conservation of mass and Darcy's law for the isothermal flow of fluids of small and constant compressibility yields the radial diffusivity equation,  In the derivation of this equation, it is assumed that compressibility of the total system, ct, is small and independent of pressure; permeability, k, is constant and isotropic; viscosity, μ, is independent of pressure; porosity, ϕ, is constant; and that certain terms in the basic differential equation (involving pressure gradients squared) are negligible.
Water production normally increases as fields mature, and two main ways exist to deal with the produced water. One is to dispose of the produced water into dedicated disposal wells. The other is to reinject the produced water for pressure maintenance or sweep efficiency. In 2010, a produced-water-reinjection (PWRI) project began in a giant field that involved replacing the aquifer water being injected in one of the water-injection clusters with produced water without water treatment. This project was conducted in a giant onshore field in Abu Dhabi.
Abstract The objective of this work is to analyze the pressure transient behavior in long or extended testing times to detect reservoir limits and to guarantee an optimal reservoir dynamic characterization that allows to understand, the real behavior of the producing formation since the beginning of its productive life, as well as ensuring timely decision-making. For this analysis, we considered some Extended Limit Tests (ELT) in exploratory or wildcat wells and currently producing wells in developed fields, from which we found the main well productivity associated parameters, an approximation of the optimum number of wells, drainage radii, estimated reserves to recover and the detection of reservoir limits and heterogeneities. The responses obtained were compared then, the associated problems and the causes that originated them from the design, execution and finally, during the interpretation of the Pressure Transient Analysis (PTA) were identified. Additionally, the present paper also attempts to propose a practical approximation for well drainage and investigation radii considering the nature of fractures in carbonates. The importance of this work lies in improving the initial characterization of reservoirs through the analysis of Extended Limit Tests (ELT) for reaching a greater radius of investigation; correspondingly, it is intended to implement an appropriate exploitation scheme (fit for purpose) for each field according to their characteristics and behavior shown for a good reservoir management and Optimal Number of Wells (ONW) to increase the recovery factor, risk mitigation and future investments assurance.
Loi, Grace Ming Yin (Australian School of Petroleum and Energy Resources, University of Adelaide) | Chequer, Larissa (Australian School of Petroleum and Energy Resources, University of Adelaide) | Nguyen, Cuong Cao (Australian School of Petroleum and Energy Resources, University of Adelaide) | Zeinijahromi, Abbas (Australian School of Petroleum and Energy Resources, University of Adelaide) | Bedrikovetsky, Pavel (Australian School of Petroleum and Energy Resources, University of Adelaide)
Fines migration causes significant formation damage during oil and gas production. The reliable prediction of well performance and extend of the damaged zone allow for planning and design of well stimulation for prevention, mitigation and removal of the damage. We derive a novel analytical model for production well performance during fines migration. The model includes explicit formulae for concentrations of suspended and strained fines, and the expressions for skin factor and well impedance. Ten field cases exhibit close match with the analytical model. Moreover, the tuned parameters belong to common intervals of their variation. The work provides means for reliable well behaviour prediction based on production history and coreflood data.
Rizkiaputra, Ricko (Medco E&P) | Indro, Axel Perwira (Rock Flow Dynamics) | Goesmiyarso, Satrio (Petronas Carigali) | Azhar, Ahmad Reizky (Rock Flow Dynamics) | Simanjorang, Rudini (Rock Flow Dynamics) | Laya, Krishna Pratama (Medco E&P) | Ramadhan, Dimmas (Medco E&P) | Subekti, Ari (Medco E&P)
There are several methodologies to model post-acid fracturing well performance such as implementing negative skin factor and stimulated reservoir volume local grid refinement (SRV LGR). However, the first method is too simplified to be applied in numerical simulation and the second method is too complex and time consuming. Therefore, to bridge the two methods, this paper will discuss the application of a grid virtual connection to model the well performance of acid fractured wells.
Grid virtual connection is the planar of fracture that alters the deliverability of the penetrated grid. In this study, series of analyses are performed, such as: (i) Data input quality check (QC) and validation (reservoir model and fracture model); (ii) Simulation running using the skin factor method, SRV LGR, and grid virtual connection; (iii) Comparison between the three methods regarding the streamline result and simulation running time; (iv) Model calibration (history matching) using post-fracturing data; (v) QC the result of history matching. Post-fracturing production data from two wells (X-6 & X-8) are used as the calibration point. From these analyses, the advantages and limitations of the virtual connection method will be examined.
The input for this study is the history matched simulation model (up to the period before acid fracturing) and the 2D fracturing model from the fracturing simulator, from which the fracturing parameters will be taken forward to numerical simulation. Details as follow: (i) the skin factor method is generated from the analytical model which results in equivalent skin of −5.6 and −5.9 for the X-6 and X-8 wells, respectively; (ii) Input parameters for the SRV LGR and grid virtual connection methods use the output from the fracturing simulator. There are several findings from these three methods: (i) The simulation running time for the grid virtual connection is similar to the skin factor method, while SRV LGR takes longer to finish; (ii) Streamline simulation shows the grid virtual connection method provides a sensible approximation of the physics behind the reservoir – fracture – wellbore flow which fully represents by SRV LGR method, meanwhile skin factor method only makes changes in the wellbore; (iii) The history matching process shows that the grid virtual connection and SRV LGR method could be matched with the actual production data, however the SRV LGR method is a highly non-unique solution due to the limited data input from the fracture simulator. Meanwhile, the skin factor method could not be matched with the actual data using a sensible skin. Based on these analyses, the grid virtual connection is shown to be the best (?) method to model the post-acid fracturing well performance.
This paper shows that the grid virtual connection is a technically sound method to perform a first order approximation of post-acid fracturing well performance. This method is beneficial to assessing the production gain on an acid fracturing job with sensible physical approximation and fast computational times.
To successfully mitigate a near-wellbore condensate blockage, the status of the condensate blockage must be thoroughly understood. This case study proposes a new technique of pressure transient analysis (PTA) to investigate the formation and impact of condensate banking on well deliverability. This new PTA technique was successfully applied to the largest reservoir of the high-pressure high-temperature Hai Thach field, providing valuable information in designing mitigation programs. Finally, two mitigation methods (hydraulic fracturing and condensate bank removal) were investigated to evaluate their potential production enhancement.
The entire production history with many buildups was matched systematically and simultaneously by PTA to determine the skin factor evolution in addition to reservoir permeability. An increasing trend of skin factor confirmed the presence of condensate blockage in the near-wellbore area and provided information about the time required for the condensate bank to form. In addition, the size of the condensate blockage was obtained from the radius of the radial composite reservoir model. Finally, improvement on production rate by two mitigation methods was examined using typical skin factors achieved by these methods.
Two production wells from the main reservoir of Hai Thach field were selected for this study. From observed data, the gas rate of the first well reduced rapidly from 10 MMSCF/d to 4 MMSCF/d and the second well had a low stable rate of 3 MMSCF/d. The application of PTA revealed that skin factor of the first well dramatically increased from 0 to roughly 11 and similar behavior was also captured at the second well as this value increased from 0.5 to around 5. This upward trend of skin factor confirmed the presence of condensate blockage at near-wellbore regions of these wells and it took approximately 5 months to form the condensate bank. The radius of condensate bank was also determined at roughly 14 ft and the average permeability of these wells fall in the range of 0.2 to 0.5 mD. In addition, the mitigation analysis on two production wells showed that hydraulic fracturing and condensate bank removal methods could improve well production rate up to approximately 180% and 100%, respectively.
From conventional well testing techniques, it is challenging to obtain further information of condensate bank in a near-wellbore region. This case study proposes a novel application of PTA which successfully provided in-depth knowledge of condensate blockage, such as condensate bank size and formation time. This information is crucial in designing mitigation programs to improve recovery of affected wells. The potential enhancement on production rate from different condensate banking mitigation methods was also quantified, providing valuable information on the feasibility of such mitigation jobs.
Blonsky, Artem Vadimovich (MIPT Center for Engineering and Technology) | Mitrushkin, Dmitrii Aleksandrovich (MIPT Center for Engineering and Technology) | Kazakov, Artem Vyacheslavovich (MIPT Center for Engineering and Technology) | Filippov, Danil Denisovich (MIPT Center for Engineering and Technology) | Mokropulo, Yury Ivanovich (MIPT Center for Engineering and Technology) | Bazanov, Ilya Evgenevich (MIPT Center for Engineering and Technology) | Shcherbakov, Georgii Yurievich (Gazpromneft STC LLC) | Melnikov, Alexander Viktorovich (Gazpromneft STC LLC) | Roshchektaev, Aleksei Petrovich (Gazpromneft STC LLC) | Maltcev, Andrei Andreevich (Gazpromneft STC LLC) | Morozov, Maxim Aleksandrovich (Gazpromneft Orenburg LLC)
Abstract In this paper it is described the approach of constructing the design of acid treatment and the tools of the software designed to solve this problem. The developed simulator includes a hierarchy of calculation modules that differ in the degree of detail of the physical effects. In addition, a number of engineering modules was developed as a part of the simulator: well data preprocessing module, history-matching module, optimization module. The mathematical models in the simulator take into account the multicomponent composition of the liquid, an arbitrary number of minerals in the solid phase, and an arbitrary number of kinetically controlled heterogeneous and homogeneous chemical reactions. Moreover, the models take into account the non-Newtonian rheology of diverters and the thermal effects during chemical reactions. The geometry of the well and hydraulic fractures can be explicitly resolved on 3D Voronoi grid in the framework of developed approach. The developed algorithms were tested by real data. It is demonstrated that precipitation resulting from secondary and tertiary reactions can have a determining effect on the result of acid treatment. The article presents the results of simulation acid treatment in a vertical well with a colmated hydraulic fracture. It is shown that acid treatment led to complete restoration of the fracture conductivity. The results of the two acid treatments analysis are also presented. When analyzing the first work it was possible to determine the reasons for the unsuccessful treatment by the adaptation model to the production data and to select an acid composition that provided maximum efficiency. When analyzing the second treatment for the well, an analog was found on which acid treatment was performed. The model parameters were adapted to the results of acidizing for the analog, and the parameters obtained as a result of the adaptation were used to simulate treatment at the original well, which led to the agreement of the simulation results with the real data. Then, it was shown under the result of design optimization that more intensive acid treatment should have been performed on the original well.