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Abstract This paper presents a workflow supported by field examples for modeling the Stimulated Reservoir Volume (SRV) as a Dynamic entity – constrained by validation or calibration against data from the frac treatment, flowback, production and pressure build-ups. The initial reservoir model of static properties is treated as a starting point and evolution of flow and storage are modeled as continuously variable properties using simultaneous modeling of flow and geomechanics – and hence the "dynamic" qualifier for SRV in the title of this paper. This workflow establishes the interaction between reservoir properties and completion parameters – and allows for program optimization. Emphasis is laid on (i) calibration with multiple types of independently measured field data points and (ii) construction of the simplest models which provide a useful degree of predictability, and we caution against over-parameterization through needless complexity of physical models. We first describe the calibration process – during which a model is perturbed to match various aspects of field data, and then explain the prediction process – where multiple hypothetical completion scenarios can be modeled. The results are then screened against economic metrics (e.g. completions costs vs. projected revenue from improved production) – reducing the number of hit-and-miss experiments in the field. While this paper is comprehensive and self-sufficient in its own coverage, it does focus on the physical modeling and calibration aspects, whereas a companion paper (Min et al. 2018), goes into greater detail about the predictive aspects and data analytics driven completion optimization.
Chipperfield, Simon T. (Santos Ltd.) | Wong, Jay Ron (Santos Ltd.) | Warner, David Sword (Santos Ltd.) | Cipolla, Craig L. (Pinnacle Technologies) | Mayerhofer, Michael J. (Pinnacle Technologies) | Lolon, Elyezer Pabibak (Pinnacle Technologies) | Warpinski, Norman Raymond (Pinnacle)
Abstract Many tight gas reservoirs require fracture stimulation to achieve commercial outcomes. These reservoirs can often be characterized geologically and geomechanically by high deviatoric stresses and hard, naturally fractured rock. Stimulation treatments in such reservoirs may create complex fracture networks from a combination of shear and tensile failures. Water fracs can be used in environments where shear failure is anticipated to dominate. However, few practical modeling tools exist  to identify the dominant failure modes prior to or during stimulation and  to evaluate the effectiveness of such treatments. This paper seeks to provide the engineer with a suite of tools capable of achieving these two goals. Firstly, this paper presents a dual porosity, pressure dependent permeability reservoir simulation model that was devised to honor shear failure mechanisms [also called shear dilation] using basic geological characterization. The assumptions of this model and the pragmatic selection of first order effects are discussed. Using the results of this simulation model, three families of diagnostic tools are presented. The first category is that of Treatment Diagnostics (TD) which include bottomhole pressure evaluation, injectivity and fall-off analysis. The second approach is called Seismic Based Reservoir Characterization (SBRC), which uses the microseismic to determine the stimulated rock volume (SRV) as well as provide estimates of the initial and stimulated fracture network properties. The third category is Post Treatment Diagnostics (PTD), which incorporates the evaluation of pressure drawdown characteristics. Finally, this paper compares these individual approaches and provides a workflow to evaluate data on future wells. Introduction Under some geological conditions the stimulation design for tight gas reservoirs may need to account for complexity caused by shear dilation mechanisms. In these cases, treated water with minimal or no proppant concentration [water fracs] can be the most effective stimulation method. However, few simulation models exist which account for this failure mode. The principal motivation for this study was firstly to develop a reservoir simulator to account for the first order effects of shear dilation. It was envisaged that, because of the complexity of the model, quantitative measurements of the pre and post stimulation reservoir properties would require direct history matching with the simulator. Despite this limitation, the aim was also to use the simulator to develop qualitative field-based diagnostic tools to determine the level of shear dilation contribution and to determine the effectiveness of such treatments where shear dilation dominates. Shear Dilation Concept Shear dilation is the event of sliding which results in self-propping due to irregularities or asperities on rock surfaces (Fig. 1). The self-propping effect can be a significant component driving stimulation effectiveness in some reservoirs1. Studies have shown that this failure mechanism can be created at pressures less than the minimum horizontal stress2. The geomechanical rock properties required for shear dilation to occur are high deviatoric stress, high rock strengths, brittle rock with a low tendency towards plastic deformation [high Young's modulus and low Poisson's ratio] and abundant low strength rock fabrics or natural fractures.
Copyright 2013, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Saudi Arabia section Annual Technical Symposium and Exhibition held in Khobar, Saudi Arabia, 19-22 May 2013. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract For carbonate reservoirs, it is common for completed intervals to intersect several layered reservoirs, commingling multiple zones, and to extend hundreds to more than a thousand feet in length. The long interval presents uncertainty on the key formation parameters considered in acid stimulation even with the best petrophysical measurement and interpretation available in the industry. Stimulation of such intervals can be further complicated by differential depletion between the zones and large differences in hydrostatic pressure during stimulation treatment. This paper strives to outline some of the key pitfalls that can occur due to the uncertainty in this data. Using reservoir simulations, the long term adverse impact of these pitfalls on both production and overall recovery can be shown. Based on degradable fiber and visco-elastic surfactant technologies, a new acid diverter, has been applied, along with a placement model, to optimize treatment design and to maximize diversion in heterogeneous carbonate reservoirs. The system is robust, diverting from high permeability streaks, fissures and natural fractures with very little diverting effect from the low permeability zones, and therefore generates a more uniform stimulation than conventional fluid systems. This approach has been used to optimize various stimulation campaigns on carbonate fields throughout the Middle East.
The PDF file of this paper is in Russian.
The paper describes applications of LAZURIT automated workstation software package for geological and reservoir modeling and well intervention planning for Tatneft’s producing field. The main advantages of LAZURIT models are presented. The progress in the development of 3D reservoir simulation software package is outlined. The scope of this study includes the analysis of models derived from LAZURIT package for production targets of the Romashkinskoye field and small fields in the Republic of Tatarstan. This research aims to assess geological risks associated with well intervention targets, increase well intervention efficiency, and assess geological risks related to planned wells. The research resulted in construction of 139 geological and reservoir models. Geological risks were assessed for wells selected as targets for well intervention jobs in 2016-2017 as well as for planned wells that would be drilled in 2016-2010. TatNIPIneft’s engineers have developed LAZURIT automated workstation software package for oil fields development analysis and planning. It has found wide application in the Institute. Its advantages include very fast results, and accurate history matching, so that the resultant estimates of the remaining oil reserves of ageing and mature production assets agree with real field data. Since 2012, LAZURIT models have been created for most of Tatneft’s producing fields. These models are permanently updated and extensively used for well intervention planning. The main screening criteria while well intervention planning are residual oil reserves. LAZURIT workstation contains software packages to assess residual reserves of drilled and planned wells that enable: 1) online determination of the geometry of the affected well element for well intervention targets; 2) online estimation of the extent to which the bypassed oil can be mobilized following well intervention jobs; 3) automatic assessment of initial and remaining recoverable reserves of well intervention targets. Work is underway on the creation of 3D reservoir simulation packages for LAZURIT workstation.
В ТатНИПИнефти для анализа и проектирования разработки нефтяных месторождений создан и широко применяется пакет программ автоматизированного рабочего места (АРМ) геолога «ЛАЗУРИТ», преимуществами которого являются скорость расчетов, точная адаптация по скважинам и, как следствие, согласованная с промысловыми данными оценка структуры остаточных запасов нефти для месторождений с длительной историей разработки. С 2012 г. по большинству объектов разработки ПАО «Татнефть» созданы и поддерживаются в актуальном состоянии геолого-технологические модели АРМ «ЛАЗУРИТ», которые широко используются при планировании проведения геолого-технических мероприятий (ГТМ). В статье рассмотрено использование пакета программ (АРМ) геолога «ЛАЗУРИТ» для геолого-технологического моделирования и планирования ГТМ на объектах разработки ПАО «Татнефть». Представлены основные преимущества моделей АРМ «ЛАЗУРИТ». Отмечено также развитие программного продукта в направлении создания модулей 3D гидродинамического моделирования. Объектами исследования являлись модели АРМ геолога «ЛАЗУРИТ» по площадям и залежам Ромашкинского месторождения, крупным и мелким месторождениям Татарстана. Оценивались геологические риски по скважинам с запланированными ГТМ, повышение эффективности ГТМ, геологические риске по проектным скважинам. В результате исследований на АРМ «ЛАЗУРИТ» построены 139 геолого-технологических моделей объектов разработки. Выполнена оценка геологических рисков по скважинам с планируемыми ГТМ на 2016-2017 гг. и проектным скважинам, планируемым к бурению в 2016-2020 гг. Полученные результаты переданы в геологические службы нефтегазодобывающих управлений. Основными оцениваемыми параметрами при планировании ГТМ являются остаточные извлекаемые запасы по участку скважины. В АРМ геолога «ЛАЗУРИТ» реализованы программы оценки остаточных запасов пробуренных и проектных скважин, которые позволяют определять геометрию элемента воздействия скважины с планируемым ГТМ в интерактивном режиме; оценивать степень активизации недренируемых извлекаемых запасов после воздействия в интерактивном режиме; подсчитывать начальные и остаточные извлекаемые запасы по элементу воздействия в автоматическом режиме.
Abstract Relative Permeability Modifying (RPM) gels are cross-linked polymers which reduce the water and oil relative permeability disproportionately and reduce the water production from a single well. RPM gels are the preferred choice for water shut-off when a well with no zonal isolation is producing from multiple layers among which, no cross-flow exists and at least one layer is producing relatively dry oil. In these conditions application of RPM gels limits the water production until water block or rarely gel desorption ends the favorable effect of the RPM gels. In this study, a black oil reservoir in north of Germany is screened to examine the feasibility of RPM gels water shut-off treatment. This homogeneous reservoir has been under production for the past 25 years and is heavily water-flooded from early years of production due to its weak drive mechanism. The reservoir is producing with an average of 75 % water-cut and requires urgent water shut-off solutions. In this paper the screening process with additional focus on the simulation stage of the screening process is described in details. The reason for the additional focus on the simulation part is lack of documented studies on simulation aspect of such projects which has led to non- negligible problems in simulating such treatments. Once the reservoir is screened considering the petro physical properties of the rocks surrounding the production wells, a water shut-off index is defined for each of the production wells which takes into account the necessity of the well for treatment as well as the risks involved by the quality of the simulation model. Based on the water shut-off index the most promising well is chosen and 3 cycles of RPM gel injection in this well is simulated. Several scenarios are defined to find out the optimum gel volume based on the incremental oil production. The best scenario resulted in 1.54 Million bbl of field incremental oil compared to the "do nothing scenario" in a period of 8 years, performing 3 consecutive gel injections. It is tried to present a detailed work-flow for screening and appraisal of such projects for the similar reservoir and operational conditions.