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Zhang, Lufeng (State Key Laboratory of Petroleum Resource and Prospecting, China University of Petroleum at Beijing) | Zhou, Fujian (State Key Laboratory of Petroleum Resource and Prospecting, China University of Petroleum at Beijing) | Feng, Wei (Dipartimento di Geoscienze, Universita degli Studi di Padova) | Cheng, Jiaqi (State Key Laboratory of Petroleum Resource and Prospecting, China University of Petroleum at Beijing)
As proved from both experimental tests and field applications, diversion agents can effectively plug the previously artificial fractures or natural fractures to create reorientation fractures, which can improve diversion efficiency and stimulated reservoir volume (SRV). However, the temporary plugging mechanism and its influencing factors were still unclear. In light of this, a fracture temporary plugging evaluation system was proposed by this study, which holds large fracture scale, and high pressure-bearing capability. Hence, this setup can meet the requirements of plugging tests. Moreover, in order to enhance the experimental accuracy, the 3D printing technique was introduced, which can reproduce the real surface morphology of acid-etched fracture. Based on the newly designed setup, some experiments were performed to study the plugging rules of fibers and the combination of fibers and particulates. Furthermore, the inner plugging mechanisms of the different cases were also analyzed. Experimental results show that the pure fibers and the combination of fibers and particulates both can achieve favorable plugging effect. In addition, the plugging processes of pure fibers can be summaried as follows: 1) The carrier fluid with fibers flow into the fracture model and a small amount of fibers remain in the fracture.
The development and management of naturally fractured reservoirs (NFRs) is a challenging task for asset teams due to the complexity of these reservoirs. The challenges are observed from the initial exploration phase and continue up to the field development stage. Placing production and injection wells in NFRs pose serious challenges. In most cases, highly permeable fractures are encountered during drilling leading to substantial loss of drilling fluids and extensive use of loss circulation materials. Thus, asset teams need to proactively predict location of these highly conductive fractures since they act as channels for rapid water or gas movement leading to early breakthrough and poor volumetric sweep efficiency.
ABSTRACT: In Brazil, the discovery of carbonate reservoirs in the pre-salt fields has raised several engineering challenges, particularly in the oil production forecasting. Carbonate reservoirs are much stiffer than conventional reservoirs. Consequently, under certain levels of deformation, fractures can develop, reactivate and/or propagate, forming complex fracture networks. Indeed, the enhanced permeability found in pre-salt reservoirs has been directly associated with the presence of hydraulically active fractures, providing those fields with high production capacity. However, the pressure changes induced during the production phase can affect the geomechanical and hydraulic behavior of such fractures. From a geomechanical point of view, the stresses induced on the fracture surfaces can trigger processes such as opening and closure of the fractures. In turn, changes in fracture apertures can alter the flow process along and across fractures. In order to predict those phenomena, this work presents a numerical model of oil production in a naturally fractured reservoir. For such, we have implemented a methodology based on zero-thickness interface elements for explicit fracture representation in an in-house finite element simulator. In order to represent the geomechanical behavior of the fractures, Mohr-Coulomb criterion is adopted together with a traction-separation law based on the model proposed by Bandis. Parallel plate law describes the longitudinal fluid flow along the fracture. According to the results, the stress changes that develop particularly around wells can affect significantly the oil production during the lifecycle of a naturally fractured reservoir. Furthermore, these results may contribute to a better understanding of the fracture behavior and can help to optimize reservoir production and well performance.
Currently, the Brazilian pre-salt fields are among the most important oil reserves in the world. Since their discovery in 2010, the production of such fields has increased exponentially, reaching 1.5 million of barrels per day (BPD) in 2018. Most pre-salt reservoirs are located below 2000 m water depth and 3000 m rock, including a salt layer of variable thickness around 2000m (Beltrão et al. 2009). The reservoirs are composed by extremely heterogeneous carbonate formations. Wellbore image logs and pressure-transient tests from those carbonate formations have indicated the presence of vugs and fractures (Vianna Filho et al. 2015). Those cavities in the carbonate rocks are responsible for the remarkable porosity in the reservoirs that averages 12% but can exceed 25% (Boyd et al. 2015). Furthermore, in comparison with conventional reservoirs, the pre-salt reservoir formations are much stiffer and present a fragile behavior. Consequently, most of those formations are naturally fractured. Actually, the large range in permeability that varies from 0.1mD to 100mD is attributed to the presence of such fractures.
Hadidi, Shahab (Petroleum Development Oman) | Yaarubi, Hilal (Petroleum Development Oman) | Baaske, Uwe (Petroleum Development Oman) | Suwannathatsa, Sakharin (Petroleum Development Oman) | Farsi, Shadia (Petroleum Development Oman) | Bazalgette, Loic (Petroleum Development Oman) | Hamdoun, Lana (Petroleum Development Oman)
The infill potential of one of the most complex fractured carbonate reservoirs in the Sultanate of Oman has been evaluated through the integration, visualization and analysis of different data sources. The field has been split into different simplified genetic geobodies which contain the culmination of facies changes that define rock quality, fluid fill, oil saturation distribution and fracture network, amongst other properties that affect fluid flow. The long production history of more than 45 years, along with the large number of logged long horizontal wells scattered around the field, were key enabler for the analytical methodology.
Production data, coupled with resistivity logs in horizontal wells, viewed through time were the backbone of the analysis. Data analysis was achieved by combining these data in a single platform and performing the analysis at different slices of time. At each timeslice, different interpretations were inferred that explain the observed production behaviour and remaining oil saturation from the logged wells. The interpretations were narrowed down into a minimum number of realizations by combining interpretations from the same area gathered from different slices of time.
The analysis has resulted in the identification of four genetic performance regions in the field. Each region approximates a primary depositional facies belt and has a general defined relative behaviour of initial wells potential, water-cut development, initial and remaining oil saturation and, most importantly, infill wells potential. The analysis has aided in narrowing the subsurface uncertainties and has given a promising explanation for the large variations in wells behaviour. Infill wells opportunities have been identified, selected and ranked relatively in each of the regions.
The value of data analytics on large volumes of acquired information normally not used was demonstrated. Visualization of different data sources in one platform is a challenging task that usually stops engineers from experimenting. The team has found fit for purpose solutions to visualize different data sources through time. The shift of mind-set from uncertain complex models and evaluations into finding simple genetic performance regions of the reservoir was vital in unravelling infill potential.
The PDF file of this paper is in Russian.
The R. Trebs oilfield, located in the Nenets autonomous district, belongs to the Timano-Pechora oil-and-gas bearing province. Reservoir is characterized by the complex structure (fractured-vugular-porous type), poor continuity of producing formation in terms of thickness and quality (both in square and section), amplitude faults network and erosion zones. These properties cause uncertainties in localizing remaining oil reserves and composition of inflow in drilled wells. This paper presents an integrated approach that helps to evaluate secondary porosity parameters for undeveloped areas of the R. Trebs oilfield. In the framework of this approach, geological and hydrodynamic modeling, modeling of a discrete fracture network occur iteratively, which makes it possible to jointly use field data, hydrodynamic well data, interpretation results of seismic, flow and geomechanical core research, image and acoustic logging results. Each of iteration is accompanied by the adjustment of all used models. The approach allows to predict oil production levels during water-and-gas impact considering geological heterogeneity in conditions of incomplete field well development. The reliability of the hydrodynamic model is confirmed by the successful prediction of the values of the initial reservoir pressure and the initial production rate of oil production at the new wells. The novelty of the work is redesigning of discrete fracture net, interpreting of seismic data during adaptation process of reservoir simulation model. It significantly changed vision of the reservoir structure and allowed to extend a new vision to the entire oilfield.
Месторождение нефти и газа им. Р. Требса расположено в Ненецком автономном округе, относится к Тимано-Печорской нефтегазоносной провинции. Резервуар трещинно-каверново-порового типа характеризуется сложным строением, невыдержанностью толщин и коллекторских свойств продуктивных пластов как по площади, так и по разрезу, наличием сети амплитудных разломов, зон размыва и зон эрозии. Указанные обстоятельства обусловливают значительные сложности, возникающие при локализации остаточных запасов нефти и газа, прогнозировании наличия и характера притока в пробуренных скважинах. Предложен комплексный подход, позволяющий определять параметры вторичной пустотности на неразбуренных участках месторождения им. Р. Требса. В рамках данного подхода итерационно осуществляется геологическое и гидродинамическое моделирование, моделирование дискретной сети трещин, что позволяет совместно использовать промысловые данные, данные гидродинамических исследований скважин, результаты интерпретации сейсмических исследований, потоковых и геомеханических исследований керна, результаты интерпретации имиджевых и акустических каротажей. Каждая итерация сопровождается корректировкой всех используемых моделей. Применение предложенного подхода позволяет прогнозировать уровни добычи нефти при водогазовом воздействии с учетом геологической неоднородности в условиях неполной разбуренности месторождения. Достоверность результатов геолого-гидродинамического моделирования подтверждена успешным прогнозированием начального пластового давления и начальных дебитов нефти вводимых в эксплуатацию скважин. Новизна представленного подхода заключается во включении в процесс адаптации геолого-гидродинамической модели работ по перестроению модели дискретной сети трещин, интерпретации сейсмических данных, что позволило существенно изменить представление о строении коллектора и месторождения в целом.
ABSTRACT: Carbonate strata are unique in that sediments can become lithified soon after deposition and prior to burial or loading (e.g., by marine or meteoric cementation). The rocks that develop have appreciable strength and cohesion that enable brittle failure under the influence of gravity. Conditions of increased effective tensile stress state can develop along steep-walled carbonate shelf margins and carbonate buildups. Marine and/or meteoric processes lead to the development of early mechanical property contrast between different facies. Some facies are mechanically competent (i.e. susceptible to brittle failure) while other facies experience ductile deformation via compaction. It is challenging to isolate features that are only related to early deformation in both outcrop and subsurface settings from those that occur from burial, uplift, and tectonism. To address this challenge, we present a forward numerical modeling approach using the finite-discrete element modeling code ELFEN to simulate these early deformation processes in carbonate systems. This modeling approach requires an initial geometry, initial rock properties, gravitational loading, and failure criteria. Bathymetry data of a modern example and a digital outcrop model of ancient rocks guides initial model geometry. Initial rock mechanical properties were measured by uniaxial compressive and Brazilian tests from collected modern and ancient rock samples. Failure criteria are assigned based on expected deformation behavior (i.e., brittle or ductile). Grain-rich carbonates and reef builders are prone to in situ early cementation and are expected to behave in a brittle manner and thus are assigned a Mohr-Coulomb with a rotating Rankine crack failure model. Soon after deposition mud-rich carbonate facies are expected to be prone to compaction and thus are assigned a modified CAM clay model that allows for compaction and porosity loss with increasing gravitational load. Modeling results are useful in determining most important variables to early fracturing and provide fundamental understanding of early deformation processes in strata that are known fractured carbonate reservoirs.
Syndepositional fracture and fault development has been documented in carbonate systems where lithification can commonly occur by meteoric and marine cementation prior to burial (e.g., Della Porta et al., 2004; Frost and Kerans, 2009; Kosa and Hunt, 2006; Verwer et al., 2009). These fracture and fault networks dictate early permeability anisotropy and influence subsequent diagenesis and deformation patterns (Budd et al., 2013; Frost et al., 2012). Syndepositional fractures can be a major contributor to permeability and hydrocarbon flow in giant carbonate reservoirs (e.g., Albertini, et al., 2013, Collins et al., 2013; Fernandez- Ibanez et al., 2016). Several challenges impede complete characterization of such fractures including insufficient sampling from the subsurface, outcrop quality, and overprinting by subsequent deformation or diagenesis. Here we address this challenge by a numerical modeling approach in which we simulate early fracture development in response to gravitational forces.
Nath, Fatick (University of Louisiana at Lafayette) | Salvati, Peter E (University of Louisiana at Lafayette) | Mokhtari, Mehdi (University of Louisiana at Lafayette) | Seibi, Abdennour (University of Louisiana at Lafayette) | Hayatdavoudi, Asadollah (University of Louisiana at Lafayette)
Strain is a critical parameter in the calculation of elastic rock properties, yet its conventional methods for strain measurement has several deficinies. In this paper, we analyze the application of optical methods with Digital Image Correlation (DIC) technique to provide detailed information regarding fracture patterns and strain development with time under Brazilian testing condition. The effect of porosity, rock types, lamination, and saturation on tensile strength will be also discussed. To examine the effect of rock type, 60 samples of sandstone (Parker, Nugget and Berea) and carbonate formations (Winterset limestone, Silurian dolomite, Edward Brown and Austin Chalk) were testedunder dry and saturated conditions and with regard to lamination angle in laminated samples. A Vic-snap photogrammetry system was employed to monitor the samples in non-contact manner while conducting indirect tensile experiment. DIC is based on the photogrammetry system, which helps to visualize and examine rock fracture pattern from the recorded images of the rock before and after deformation by assessing the strain development in samples. The experimental results show that - (1) average tensile strength declines while increasing porosity for homogeneous, laminated, and heterogeneous rock specimens.
Zhang, Ping (Schlumberger) | Abdallah, Wael (Schlumberger) | Ramadhan, Moemen (Schlumberger) | Marsala, Alberto (Saudi Aramco) | Saif, Sarah (Saudi Aramco) | Lyngra, Stig (Saudi Aramco) | Ma, Shouxiang (Saudi Aramco)
The results of the 3D inversions and saturation mapping of a crosswell electromagnetic (EM) survey conducted between two horizontal wells are presented. The project was designed to understand the remaining fluid saturation in a naturally fractured carbonate reservoir. A crosswell EM survey was acquired between a 1-km-long horizontal water injector and an equally long horizontal producer, spaced 1.3 km apart. This survey was the world's first crosswell survey between two horizontal wells.
Extensive pre-survey simulation model results established that the crosswell EM method has sufficient depth of investigation and resolution to define fractures and provide locations of by-passed hydrocarbons in this setting. The acquired data provided a solid foundation for 3D inversions. The final 3D inversion yielded a resistivity model with clearly defined low- and high-resistivity areas. Aided by reservoir simulations, the resistivity model was converted to a 3D water saturation distribution, which connects the low-resistivity volumes with fracture zones filled with water, and high-resistivity volumes with possibly unswept rock matrix. A well was drilled to test an indicated high-resistivity area. The well penetrated an oil column and is currently on production. The resistivity log from the newly drilled well compared favorably with the data extracted from the inverted 3D resistivity model.
Presentation Date: Monday, September 25, 2017
Start Time: 2:40 PM
Presentation Type: ORAL
Carbonate formation is an ideal candidate for geological CO2 sequestration (GCS) because of its large storage capacity. One of the important issues is the CO2 leakage through highly conductive pathways. During a GCS process, the dissolved CO2 can form a weak acid in brine that can dissolve carbonate rocks by various geochemical reactions. Carbonate rocks are composed of a variety of minerals, including calcite, quartz, clay, etc. Such dissolution process may enhance the existing natural fracture system to eventually form highly conductive pathways for possible CO2 leakage.
In this paper, we have developed a numerical model that couples the Stokes-Brinkman equation instead of the Darcy's Equation and a reactive transport equation, and applied for modeling of the coupled process consisting of fluid flow, solute transport, and chemical reactions. Compared to the Darcy's equation, the Stokes-Brinkman equation is a unified approach for modeling fluid flow in both porous media and free flow regions, which is an ideal candidate for modeling of porosity alteration and fracture enhancement due to mineral dissolution. The nonlinear reactive transport equations are derived for primary species from mass balance equations. In the numerical model, the Stokes-Brinkman equation and the transport reactive equations are solved by a mixed finite element method and the control-volume finite difference method, respectively, in a sequential fashion.
The numerical model is validated using a CO2-saturated brine flooding experiments from the existing publications. Good agreements of effluent concentrations of aqueous species can be found between our simulation results and experimental observations. The numerical simulation study focuses on core-flooding scenarios with different mineral volume fractions and different injection rates in fractured rocks composed of multiple minerals. The preliminary results demonstrated that the mineral volume fractions have significant impact on the porosity alteration and fracture propagation. The calcite dissolution is preferred in acidic fluids over less reactive minerals including quartz and clay, and the rock properties are altered accordingly. The competitive coupling between the flow and chemical reaction rates is another important factor for mineral dissolution in our simulation study. In addition, the simulation results demonstrated that mineral dissolution processes can be altered by controlling the injection rates because the chemical reactions in the GCS processes are reversible.
This work presents a mathematical model allowing us to simulate the dynamic behavior of natural fracture evolution during the GCS processes, and provides some important guidelines for the GCS implementation. Currently, we are trying to apply the simulation technology for solving some real-world problems.
In this paper, geomechanics is coupled with reservoir flow for modeling the depletion and deformation in fractured vuggy carbonate reservoir. Different from the dual- and triple-porosity models or the coupled approaches in which the vugs are considered as a continuous porosity, the vugs are treated as virtual volumes in this study. For each vug, the fluid exchange at the vug-matrix interface is dynamically calculated with time evolution and the pore pressure in the vugs is updated through considering both the fluid material balance and the volume change due to the mechanical deformation of vug. The fluid-mechanical interaction in the rock matrix and natural fractures is calculated based on the framework of Biot's poroelstic theory. The mechanical and hydraulic interactions between vugs and matrix are preserved and the stress evolution due to the depletion can be dynamically updated. The results in this study show that, the depletion process is mainly controlled by the fluid storage of the vugs. Fluid modulus is thus a more sensitive parameter than the rock/fracture modulus in terms of the depletion. However, the rock/fracture modulus can also affect the deformation of the system and thus affect the volume and pressure changes of the vugs.