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Liang, Xingyuan (China University of Petroleum at Beijing) | Zhou, Fujian (China University of Petroleum at Beijing) | Liang, Tianbo (China University of Petroleum at Beijing) | Wang, Rui (China University of Petroleum at Beijing) | Su, Hang (China University of Petroleum at Beijing) | Wang, Xinglin (Rice University)
Liquid nanofluid (LNF) is being gradually used in unconventional reservoirs. However, the application of LNF during hydraulic fracturing in tight reservoirs needs to be further investigated. In this study, a series of experiments were conducted to discuss the above problem. First, a new method to evaluate wettability in different pore-scale was provided. Then core flooding experiments were conducted to study invasion pressure for the LNF. Finally, the efficiency of drag reduction after adding the LNF was evaluated. The result showed that imbibition and nuclear magnetic resonance (NMR) can be combined to evaluate the average wettability for the unconventional rock. Core flooding experiments stated that the LNF could reduce the invasion pressure, which would enhance the effective volume. Drag reduction experiments demonstrate that LNF makes drag reduction more efficient. Field application proved the LNF could help enhance the production in tight oil reservoirs. Several advantages of using LNF in the process of hydraulic fracturing were also revealed.
The tight oil reservoir has been one crucial part of petroleum resources (Hu et al., 2019; Li and Misra, 2018; Liang et al., 2020a). The hydraulic fracturing and horizontal well have been two main technologies to explore the tight and other unconventional reservoirs(Liang et al., 2020b; Wang et al., 2019, 2015, 2020b). However, the production decreases rapidly on account of low permeability and complex pore structure(Liang et al., 2017; Wang et al., 2020a). Imbibition has been one of the important methods to enhance oil recovery in unconventional reservoirs(Liang et al., 2020c; Liu et al., 2019; Meng et al., 2016). Imbibition help replaces the oil into fractures and helps increase production. Wettability is one of the most important factors, which influence the imbibition oil recovery. As we all know, the aqueous phase can be spontaneously imbibed into the rock with water-wet; while the rock with oil-wet cannot imbibe aqueous fracturing fluid spontaneously. The rock has been turned into oil/mix wet after contacting with crude oil for hundreds of years, especially for carbonate minerals. Wettability testing is much important so that people can understand the potential imbibition ability for the reservoir. Besides, people could evaluate the wettability alteration after using chemical additive, like surfactant or micro emulsion.
Special Core Analysis, SCAL data has a direct impact on the way fluids are allocated and distributed in the reservoir simulation models, which would directly impact reservoirs' STOIIP estimation and their distribution. Moreover, it directly affects the performance of secondary and EOR flooding processes, and in turn impacts the accuracy of the oil and gas reserve estimates, and the management of these reserves. Therefore, SCAL data could be considered as one of the most critical reservoir input data for reservoir simulation models. This course will shed light on the theoretical and experimental background of SCAL data. It will explain the concept of reservoir wettability and different factors that could induce changes in reservoir wettability.
Special Core Analysis, SCAL data has a direct impact on the way fluids are allocated and distributed in the reservoir simulation models, which would directly impact reservoirs’ STOIIP estimation and their distribution. Moreover, it directly affects the performance of secondary and EOR flooding processes, and in turn impacts the accuracy of the oil and gas reserve estimates, and the management of these reserves. Therefore, SCAL data could be considered as one of the most critical reservoir input data for reservoir simulation models. This course will shed light on the theoretical and experimental background of SCAL data. It will explain the concept of reservoir wettability and different factors that could induce changes in reservoir wettability.
We investigate the effect of heterogeneous petrophysical properties on Low Salinity Water Flooding (LSWF). We considered reservoir scale models, where the geological properties were obtained from a giant Middle East carbonate reservoir. The results are compared against a typical sandstone model.
We simulated low salinity induced wettability changes in field scale models in which the petrophysical properties were randomly distributed with spatial correlation. We examined a wide range of geological realisations which mimic complex geological structures. Sandstone was simulated using a log-linear porosity-permeability relation with fairly good correlation. A carbonate reservoir from the Middle East was simulated where a much less correlated porosity permeability relationship was obtained. The salinity of formation water was set to typically observed values for the sandstone and carbonate cases. A number of simulations were then carried out to assess the flow behaviour.
We have found that the general trend of permeability-porosity correlation has a key role that could mitigate or aggravate the impact of spatial distributions of petrophysical properties. We considered models with a log-linear permeability-porosity correlation, as generally observed for sandstone reservoirs. These are likely to be directly affected by the spatial distribution more than models with a power permeability-porosity correlation, which is often reported for flow units of carbonate reservoirs. The scatter of data in the permeability-porosity correlations had a relatively small impact on the flow performance. On the other hand, the effect of heterogeneity decreases with the width of the effective salinity range. Thus, uncertainty in carbonate reservoirs arises due to the ambiguity of spatial distribution of permeability and porosity would be less affects the LSWF predictability than in sandstone case. Overall, the incremental oil recovery due to LSWF was higher in the carbonate models than the sandstone cases. We observe from uncertainty analysis that the formation waterfront was less fingered than the low salinity waterfront and the salinity concentration. The dispersivity of salinity front and the water cut can be estimated for models with various degrees of heterogeneity.
The outcome of the study is a better understanding of the implications of heterogeneity on LSWF. In some cases the behaviour can appear like a waterflood in very heterogeneous cases. It is important to assess the reservoir effectively to determine the best business decision.
Many oil reservoirs worldwide have cycle dependent oil recovery either by design (e.g. WAG injection) or unintended (e.g. repeated expansion/shrinkage of gas cap). However, to reliably predict oil recovery involving three-phase flow process, a transformational shift in the procedure to model such complex recovery method is needed. Therefore, this study focused on identifying the shortcomings of the current reservoir simulators to improve the simulation formulation of the cycle-dependent three-phase relative- permeability hysteresis.
To achieve this objective, several core-scale water-alternating-gas (WAG) injection experiments were analysed to identify the trends and behaviours of oil recovery by the different WAG cycles. Furthermore, these experiments were simulated to identify the limitations of the current commercial simulators available in the industry. Based on the simulation efforts to match the observed experimental results, a new methodology to improve the modelling process of WAG injection using the current simulation capabilities was suggested. Then the WAG injection core-flood experiments utilized in this study were simulated to validate the new approach.
The results of unsteady-state WAG injection experiments performed at different conditions were used in this simulation study. The simulation of the WAG injection experiments confirmed the positive impact of updating the three-phase relative-permeability hysteresis parameters in the later WAG injection cycles. This change significantly improved the match between simulation and WAG experimental results. Therefore, a systematic workflow for acquiring and analyzing the relevant data to generate the input parameters required for WAG injection simulation is presented. In addition, a logical procedure is suggested to update the simulation model after the third injection cycle as a workaround to overcome the limitation in the current commercial simulators.
This guideline can be incorporated in the numerical simulators to improve the accuracy of oil recovery prediction by any cycle-dependent three-phase process using the current simulation capabilities.
Polymer flooding is a mature chemical enhanced oil recovery (CEOR) technology with over forty years of laboratory- and field-scale applications. Nevertheless, polymers exhibit poor performance in carbonates due to their complex nature of mixed-to-oil wettability, high temperature, high salinity, and heterogeneity with low permeability. The main objective of this study is to experimentally evaluate the performance of a biopolymer (Scleroglucan) in carbonates under harsh conditions of temperature and salinity. This experimental investigation includes polymer rheological studies as well as polymer injectivity tests. Rheological studies were performed on the biopolymer samples to measure the polymer viscosity as a function of concentration, shear rate, salinity, and temperature. Injectivity characteristics of this biopolymer were also examined through corefloods using high permeability carbonate outcrops. The injectivity tests consisted of two stages of water pre-flush and polymer injection. These tests were conducted using high salinity formation water (167,000 ppm) and seawater (43,000 ppm) at both room (25 °C) and high temperature (90 °C) conditions.
The rheological tests showed that the biopolymer has a high viscosifying power and it exhibits a shear-thinning behavior that is more prevalent at higher polymer concentrations. Also, a pronounced effect was observed for water salinity on both polymer filterability and polymer injectivity. The biopolymer exhibited better filterability at the high temperature as opposed to the room temperature. From the injectivity tests, the shear-thinning behavior of this biopolymer in the porous media was confirmed as the resistance factor decreased with increasing the flow rate applied. The potential biopolymer showed good injectivity at both the room and the high temperatures. This study provides further insight into the performance of this biopolymer in carbonate reservoirs and encourages further application under harsh conditions of salinity and temperature.
The PDF file of this paper is in Russian.
This article proposes a method for selecting of optimal oil field development system using a two-dimensional semi-analytical simulator, based on solving of Laplace equation for calculating pressure fields and using the Buckley – Leverett theory with the method of current lines for calculating saturation fields, taking into account the geological heterogeneity of the reservoir. The account of geological heterogeneity in the two-dimensional simulator is made by means of dependence of the grid coverage coefficient on length of the current line. The distribution of current line lengths in the three-dimensional hydrodynamic model characterizes the geometry of sand bodies and geological heterogeneity of the reservoir, and the value of the grid coverage coefficient numerically expresses this heterogeneity. This approach makes it possible to speed up the process of selecting the optimal parameters of development (density of the well grid, types of well completion, parameters of the hydraulic fracturing design on producing wells, half-length of fractures after auto-fracturing on injection wells, value of bottom-hole pressure on producing and injection wells, deformation coefficient for the grid of wells, etc.) at the decision-making stage. The parameter for choosing of the optimal development system, i.e. its optimal parameters, is the maximum value of the net present value when the conditions for achieving of the design oil recovery ratio are met. The calculation of economic parameters is carried out according to the dependencies inherent in the two-dimensional semi-analytical simulator, which allows the entire cycle of technical and economic analysis in one tool. In particular, this technique is extremely relevant for fields with low permeability and disjointed reservoir. Since the key feature of this approach is the account of geological heterogeneity.
В статье предложена методика выбора оптимальной системы разработки нефтяного месторождения при помощи двумерного полуаналитического симулятора, основанная на решении уравнения Лапласа для расчета полей давления и использовании теории Баклея – Леверетта с применением метода линий тока для расчета полей насыщенности, с учетом геологической неоднородности пласта. Пространственная геологическая неоднородность, заложенная в трехмерной модели, учитывается в аналитическом симуляторе через использование специальным образом сконструированной зависимости коэффициента сетки скважин от длины линии тока. На этапе принятия основных решений при составлении проектно-технической документации на разработку месторождения данный подход позволяет значительно ускорить процесс выбора оптимальных параметров разработки, таких как плотность сетки скважин, тип заканчивания скважины, параметры дизайна гидроразрыва пласта (ГРП) в добывающих скважинах, полудлина трещин автоГРП в нагнетательных скважинах, забойное давление в добывающих и нагнетательных скважинах, коэффициент деформации сетки скважин и др. Критерием выбора оптимальной системы разработки, т.е. ее оптимальных параметров, является максимальное значение чистого дисконтированного дохода при выполнении условия достижения проектного коэффициента извлечения нефти. Расчет экономических параметров проводится по зависимостям, заложенным в двумерный симулятор на трубках тока, что позволяет осуществлять весь цикл технико-экономического анализа в одном инструменте. Ключевой особенностью предложенной методики является учет геологической неоднородности в двумерном симуляторе, что особенно актуально при проектировании разработки месторождений с низкопроницаемыми и слабосвязанными коллекторами.
The Haft Kel field is located in Iran. Its Asmari reservoir structure is a strongly folded anticline that is 20 miles long by 1.5 to 3 miles wide with an oil column thickness of approximately 2,000 ft. The most probable original oil in place (OOIP) was slightly 7 109 stock tank barrels (STB) with about 200 million STB in the fissures; numerical model history matching resulted in a value of 6.9 109 STB. The matrix block size determined from cores and flowmeter surveys varied from 8 to 14 ft. The numerical simulation model considered matrix permeabilities from 0.05 to 0.8 md.
Aglyamov, Mansur (Schlumberger) | Molero, Nestor (Schlumberger) | Nabki, Felix (Schlumberger) | Mhiri, Adnene (Schlumberger) | Momin, Muhammad (Schlumberger) | Al-Mashhadani, Hussein Essa (Schlumberger)
Efficient reservoir sweep is critical for operators to boost oil production in the Middle East. This task becomes particularly challenging in carbonate formations, which typically feature permeability ranging from microscopic pores to large cavernous vugs. Extreme heterogeneity disserves water injectors, leading to nonuniform injection profiles. Consequently, water sweeping is inefficient and leaves significant residual oil behind. In the Mesopotamian Basin, the matrix stimulation approach was rethought to address high permeability contrasts and produce the bypassed oil.
The methodology relied on coiled tubing (CT) equipped with fiber optics and real-time downhole measurements, a CT-deployed inflatable packer, and a high-pressure rotary jetting tool. The array of downhole readings was leveraged to ensure optimal use of the bottomhole assembly. The high-pressure rotary jetting tool was used in the first run to condition the wellbore tubulars across the inflatable packer planned anchoring depth. In the second run, the inflatable packer was set at the target depth, and the stimulation treatment was selectively pumped either above or below the packer, depending on the depth of the interval of interest.
The proposed stimulation technique was implemented in more than 40 wells, which included vertical and deviated water injectors, completed with 3 1/2-in. or 4 1/2-in. tubing and up to 7-in. casing, with two to five perforated intervals averaging 30 to 50 m in total, temperatures ranging from 90 to 140°F, and an average meadured depth of 2500 m. The CT-deployed inflatable packer had an expansion ratio of up to 3 to 1. CT real-time downhole measurements, such as CT internal pressure, CT annulus pressure, temperature, downhole axial forces, gamma ray, and casing collar locator (CCL), were instrumental to eliminate the uncertainties associated with changing downhole conditions and depth correlation. They also enabled a controlled actuation of the downhole tools in subhydrostatic wells, as the pressure imbalance caused by the low bottomhole pressure can generate loss of fluid flow and pressure across the tools. For the first time, the operator was able to stimulate the tight rock in water injector wells, enhancing injection sweeping efficiency and boosting oil production from offset wells. As a result of this campaign, production gains are estimated at 60,000 BOPD, and injectivity increased in average 2 times per intervention. This approach has now become the state of the practice for the operator to stimulate wells with high permeability contrast.
This enhanced matrix stimulation technique, leveraged by CT and real-time downhole measurements, brings a new level of confidence to accurately and effectively deploy inflatable packers in wells with challenging expansion ratio and low reservoir pressure. In addition, the proposed technique enables stimulating tight rock across intervals with extreme heterogeneity, resulting in a more efficient sweep and an increase in oil production.
It is common knowledge that over its life-cycle an oil producer or water injector may experience a reduction in near-wellbore permeability or overall fluid connectivity to or from the reservoir from in-wellbore impediments that negatively impact productivity or injection. Such permeability reductions or fluid connectivity losses are often related to near-wellbore damage or ‘skin’ or in-well damage induced by fill, scales, waxes, asphaltene or other blocking mechanisms. In recent years an increasing number of coiled tubing ("CT") stimulation and cleanout interventions has led to the advancement of downhole tools focused on remediating such damage mechanisms. One such development that has been successfully deployed to re-establish water injection rates for reservoir pressure support in oil field production operations is a multi-directional, cavitational-based fluid pulsing tool that provides a hydro-mechanical means to both remove detritus materials from the immediate wellbore but also stimulate the near-wellbore region.