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This article focuses on interpretation of well test data from wells completed in naturally fractured reservoirs. Because of the presence of two distinct types of porous media, the assumption of homogeneous behavior is no longer valid in naturally fractured reservoirs. This article discusses two naturally fractured reservoir models, the physics governing fluid flow in these reservoirs and semilog and type curve analysis techniques for well tests in these reservoirs. Naturally fractured reservoirs are characterized by the presence of two distinct types of porous media: matrix and fracture. Because of the different fluid storage and conductivity characteristics of the matrix and fractures, these reservoirs often are called dual-porosity reservoirs.
Jun, Pu (State Key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development) | Qin, Xuejie (State Key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development) | Chen, Zhiming (China University of Petroleum, Beijing) | Shi, Luming (China University of Petroleum, Beijing) | Wei, Yi (State Key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development) | Chen, Haoshu (China University of Petroleum, Beijing) | Meng, Meiling (China University of Petroleum, Beijing) | Gou, Feifei (State Key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development)
In the shale oil reservoirs, the horizontal wells with large-scale fracturing treatments have been the most effective tools to enhance oil productivity. After large-scale fracturing treatments, many micro-seismic data showed that the fracture networks are generated in the reservoir along the wellbore. Understanding the complex fracture properties is the primary step for fracturing evaluation and productivity estimation. Thus, an efficient approach is needed to estimate the fracture properties. To improve this situation, a well-testing approach was proposed in this work to identify the fracture properties. This work was organized as follows: (1) developing a well-testing model of multiple fracture horizontal well (MFHW) including reservoir flow equations, fracture flow equations, and mass balance equations, (2) solving and verifying the proposed model using boundary element method, superposition principle, and numerical approach, (3) applying the well-testing model to investigate the pressure transient behaviors, and (4) estimating the fracture properties of shale oil wells from the Junggar Basin.
Performance evaluation of water injector wells is usually done by injection and fall-off tests. However, the well test analysis of fall-off tests is often challenging because of the interaction of two immiscible fluids in the reservoir.
The paper presents a field example where six different fall-off tests, separated by large time intervals in a long injection sequence were analysed for a well injecting water in an oil reservoir. In order to reproduce the fluid interaction in the reservoir, it was essential to consider the relevant impact of temperature on the injected fluid viscosity in the near-wellbore zone due to the cold-water injection. At the wellbore scale, a temperature reduction of around 95 degree Celsius was observed with respect to the virgin reservoir temperature, which in turn led to an increment of viscosity of the injected fluid by approximately four orders of magnitude. The analysis of each fall-off showed a radial composite behaviour, with the two radial flow stabilizations depending upon the different mobility of oil and water, while the radius of interface depending upon the cumulative volume of injected water. The interpretation provided the key reservoir characteristics (formation capacity in the water-invaded and virgin oil zone, transient injectivity index, static reservoir pressure, skin, etc.) and allowed an assessment of the well injection capability and its change with time in the reservoir. Within Eni, repeated fall-off analysis in a well is becoming a powerful and cheap tool for efficient waterflood management.
Besides providing key parameters for reservoir characterization and a dynamic picture of near wellbore region, the paper highlights the peculiarities of a fall-off test and the way reliable outputs can be achieved. It demonstrates how it is crucial to consider temperature related viscosity variations and how it is the key driver for achieving accurate well test results.
The injection of fluids in hydrocarbon reservoirs is a widely used method to achieve higher recovery factors and increase recoverable reserves. Particularly, water injection in oil reservoirs represents an important secondary recovery method in deepwater oilfields operated by Eni due to the low associated costs.
Tariq, Zeeshan (King Fahd University of Petroleum & Minerals) | Abdulraheem, Abdulazeez (King Fahd University of Petroleum & Minerals) | Khan, Mohammad Rasheed (King Fahd University of Petroleum & Minerals) | Sadeed, Ahmed (King Fahd University of Petroleum & Minerals)
Abstract The idea of continuous assessment of individual well performance is imperative globally to E&P organizations when it comes to production optimization regimes and increasing profitability from each barrel of oil present. One of the most effective ways to assess this performance is through the use of Inflow-Performance Relationship (IPR) & Outflow-Performance Relationship (OPR) curves. Consequently, the use of the pertinent IPR which is representative of the performance is essential. Vogel's IPR has been employed in the industry more like a standard when it comes to conventional reservoirs well performance. Moreover, Vogel's IPR model can successfully model IPR for vertical wells in a homogeneous reservoir producing from solution gas drive mechanism. However, current IPR models for horizontal wells are only valid for single porosity reservoirs, and their applicability to dual porosity/dual permeability reservoirs is questionable. The complexity in such reservoirs arise due to the combined flow between the distinct systems of the matrix and fracture, and as a result, it is imperative to develop a new IPR model that incorporates the impact of the fracture parameters. This work focuses to inspect effects of the complex flow behavior on the inflow curves, concentrating on horizontal wells in NFR's. Foundation of this work is based on the development of a base case black oil computational model incorporating typical reservoir and PVT properties. Finite number of data points linking oil rate to flowing bottom-hole pressures were used to generate the dimensionless IPR curves. Wide-ranging PVT and particular reservoir properties concerning two systems of porosity and permeability were used which included; Inter-porosity flow co-efficient, storativity ratio, normalized horizontal well length, reservoir thickness and saturation pressure. As expected, it was concluded that the NFR parameters of storativity and inter-porosity flow coefficient, along with the normalized horizontal well length had substantial control on dimensionless IPR curve. To further augment the results, effort is expended to congregate outcomes into one unpretentious model using a combination of support vector machine and non-linear regression techniques along with the particle swarm optimizer to formulate a new empirical IPR equation. The newly suggested pragmatic IPR model produces results within acceptable absolute error range of 2%, when compared with the actual data. Accordingly, this proves that the developed correlation is very accurate and can prove to be a vital tool for production/reservoir engineers concerned with the production optimization/enhancement of horizontal wells in naturally fractured dual porosity-dual permeability reservoirs.
Abstract Naturally fractured reservoirs (NFRs) are the reservoirs with two distinct types of porous media called the fracture and matrix. The pressure behavior of naturally fractured reservoirs is usually studied by using Warren and Root model (Warren and Root, 1963). Warren and Root model assumes that production from the naturally fractured system goes from the matrix to the fracture and thence to wellbore (Warren and Root, 1963). However, this assumption is oversimplified if the contrast between the permeability of matrix system and that of fracture system is not significant. In order to estimate the limits of validity of solutions based on Warren and Root model and to study the behavior of a naturally fractured reservoir when the contrast between the two permeability are not significant, it is necessary to solve the original model proposed by Barenblatt and Zheltov (Chen 1989). But the analytical solutions to this model which were obtained by numerical analysis or numerical inversion are very complex and inconvenient to use (Lu, Zhu and Tiab, 2009). Assuming that both of the matrix and fractures produce directly into the wellbore, a new mathematical model for dual-permeability naturally fractured reservoirs is presented in this paper. Based on our proposed model, it is concluded that there are four stages for the pressure behavior of NFRs; the double-permeability system behave like a reservoir with a constant pressure boundary when the dimensionless time approaches to infinite. The solution procedure proposed in this paper is a fast tool to evaluate a vertical well performance in a dual-permeability naturally fractured reservoir.
Abstract Non-Newtonian fluids have been characterized over the decades, and such characterizations may be used to model a new approach in engineering disciplines. Non-Newtonian fluids are classified as non-time dependent and time-dependent fluids. This paper focuses on the non-time dependent classification, specifically pseudoplastic fluids. The ranges in these fluids allow the proposed model to be validated. The new reservoir model accounts for non-Newtonian behavior within a double-porosity reservoir. This model demonstrates an interporosity transfer function for pseudosteady state, based on a new parameter: dimensionless matrix contribution (D). This parameter differentiates our method from previous efforts based on the pseudosteady state interporosity flow for Newtonian fluids introduced in the 1960's. We derive the partial differential equation for a non-Newtonian flow within a double porosity reservoir under pseudosteady state interporosity transfer conditions. The solution presented is for an infinite acting reservoir (assuming the corresponding initial, inner and outer conditions). The objective of this paper is to deliver and provide tools that may help to characterize double porosity reservoir under the condition that a non-Newtonian fluid is present, and the interporosity transfer conditions between a matrix system and a fracture system are in pseudosteady-state.
Tariq, Zeeshan (King Fahd University of Petroleum & Minerals) | Alnuaim, Sami (King Fahd University of Petroleum & Minerals) | Abdulraheem, Abdulazeez (King Fahd University of Petroleum & Minerals) | Khan, Mohammad Rasheed (NED University of Engineering & Technology)
Abstract Forecasting the performance of individual wells is of great importance to oil companies for continuous field production optimization and cost per barrel reduction. Well Performance is measured by evaluating the Inflow Performance & Outflow Performance Relationships (IPR & OPR). For that the need to use the correct IPR for subjected reservoir is very essential. Since many decades, Vogel IPR equation has been used comprehensively for evaluating the productivity of vertical wells in saturated gas drive reservoirs. Vogel's model successfully evaluates IPR for single porosity solution gas drive in homogenous reservoirs. However, the applicability of Vogel's IPR for naturally fractured dual porosity-dual permeability reservoirs is questionable; hence this challenge is addressed by the industry only numerically. Due to composite fluid flow behavior between fracture and matrix system in a dual porosity-dual permeability reservoir, there is a pressing need for a new, practical and simple IPR model that takes into account the consideration of fracture parameters. This study investigates the effects of reservoir complex fluid flow behavior on IPR curves for vertical wells drilled in naturally fractured oil saturated reservoirs resulting in the development of an IPR curve for such conditions. A base case simulation model is developed with typical reservoir, fluid and rock properties using black oil model. Using a set of points relating oil production rates to flowing bottom-hole pressures, the dimensionless IPR curves are generated. Fluid and reservoir properties were varied between two porous and permeable media such as Inter-porosity flow co-efficient, storativity ratio, oil gravity, reservoir thickness and bubble point pressure. Inter-porosity flow coefficient and fracture storativity ratio were found to have a significant impact on dimensionless IPR curves. Finally, an attempt is made to converge the results into one simple model using non-linear regression technique in order to get a new empirical IPR correlation for vertical well producing from naturally fractured oil reservoirs. A small and acceptable average absolute error of less than 2% was found with the new proposed empirical IPR model, while comparing the existing published correlations on the same data gives more than 15% error. The developed IPR correlation is accurate enough and can serve as a handy tool for the production engineers to forecast the productivity of wells drilled in a naturally fractured dual porosity-dual permeability saturated oil reservoirs.
Abstract In fractured reservoir, the use of the so-called cubic law represents a method to describe fluid flow through fractures and to estimate effective fracture porosity from effective fracture permeability and matrix block size. The method supposes perfect fracture connectivity. In practice, however, it often underestimates field fracture porosity. This paper explores the relation between fracture porosity, fracture permeability and matrix block size using field, and in particular well test, data. We used field data coming from four naturally fractured sand-stone reservoirs in foothills. Values of storativity ratio (ω) and inter-porosity flow coefficient (λ) coming from thirty-three pressure buildup derivatives interpretations are listed and used to estimate fracture porosity and matrix block size. The effective permeability associated to each well test, which is obtained from the stabilization of the pressure derivative, was also recorded. A non-linear regression was put in place in order to correlate fracture porosity, matrix block size and effective permeability. Obtained fracture porosities and block sizes are similar to values from other sources, such as thin section analysis and image log data. The most significant finding is that field data can be correlated by introducing in the cubic law a correction parameter that increases fracture porosity by about two orders of magnitude. The reason for deviation from the theoretical cubic law can be threefold: first, the cubic law considers the entire hydraulic aperture of the fracture as contributing to the fluid flow, while in reality the flow may be hindered by presence of cement in-filling the fracture (thin section data supports this assumption); secondly, the cubic law assumes a perfectly connected fracture network, while in real cases some fractures may die out without intersecting any other fracture; thirdly, transient flow effects and distribution of block sizes may lead to a less well pronounced dip in the derivative, which may be interpreted as a larger fracture porosity when using a pseudo steady-state model for analysis. The correction parameter is likely not universal, and will depend on the degree of fracture in-fill and connectivity in a given field. The work presented in this paper provides fracture permeability, fracture porosity, and block size estimates for the given type of environment. It issues a strong warning with respect to the application of the cubic law to estimate fracture porosity, and proposes a corrected cubic law expression that gives more accurate results. The methodology is useful for characterizing fracture porosity, a parameter that is notoriously difficult to measure.
Abstract In a previous research (IPTC 14187) a new technique was introduced to characterize all kinds of naturally fractured reservoirs on the Megascopic scale of pressure transient analyses. The technique is optimized through application of pressure derivative methods to yield a very characteristic graphical representation (triangle) of each hydraulic "flow" unit in the fractured reservoir. The graphical technique along with newly derived formulas yield the most important petrophysical and engineering parameters about the heterogeneous naturally fractured reservoir including effective fractures, matrix and skin systems volumes, partitioning coefficient, fracture intensity index, formation resistivity factor, formation tortuosity, effective drainage radius, damage radius, effective cementation exponent, fracture porosity, matrix porosity, storativity ratio, in addition to fracture permeability, matrix permeability, damaged permeability, average permeability, pressure drop across the damage area, skin factor, damage permeability, average/dimensionless diffusivity factor, flow efficiency, damage ratio/factor, economic implication of formation damage, average hydraulic "flow" unit quality index. The technique is extended to derive the fracture partitioning coefficient and intensity index in terms of storativity ratio generated from the fractured triangle of pressure transient analyses along with new fracture/matrix permeability ratio and fracture/matrix porosity ratio are introduced to aid describing the degree of reservoir heteroginity. Again the graphical technique of the fractured triangle has proven to be successful for all kinds of fractured reservoirs including clastics, carbonates and basement rocks. This study will present the theory along with successful field application with the results.
He, Liu (Research Inst. of Petroleum Exploration and Development, PetroChina) | Yingan, Zhang (Jilin Oilfield Company, PetroChina) | Honglan, Zou (Research Inst. of Petroleum Exploration and Development, PetroChina) | Yang, Gao (Research Inst. of Petroleum Exploration and Development, PetroChina)
Abstract The formations of DaQing gas field are mainly volcanic reservoirs which have the characteristics of low permittivity and complex formation structures. Most of these wells need fracturing remodeling to meet the standards of industrial gas stream, and also, the gas productivity tests as well as the pressure recovery tests conducted on these wells are different from other regular gas reservoirs. Considering the nature of the volcanic reservoir, such as dissolution pores, karsts caves, natural fracture development, we built two mathematical models of dissolution pores development and natural fracture development under both of the Darcy flow conditions and Non-Darcy flow conditions separately to predict the production of triple porosity reservoir after gas reservoir well fractures. By using the Laplace transform and numerical inversion, the equation to calculate production of complex volcanic gas wells is obtained. Based on these researches, law of volcanic reservoir productivity is investigated. The theoretical data are compared with the practical data collected from the field operation. The comparison results reveal how the parameter of the fluid volume, proppant indexes, and conductivity of artificial fracturing induced fractures and length of fractures change affect the productivity. The research work reported in this paper provides theoretical support on the optimization method of fractured wells design of volcanic gas reservoir.