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.
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.
Ahmadi Reservoir is one of the Reservoirs producing in the Bahrain Field. It has been producing for more than eighty years. Ahmadi is a tight carbonate Reservoir that belongs to the Wasia Cretaceous group. It consists of two main limestone units which are AA and AB. Like most Carbonates in the Middle East, Ahmadi production is dominated by secondary permeability which means that the reservoir has a dual exponential type Curve. Dual exponential in Ahmadi means a high flush initial production period and then a longer period of stabilized production.
Because of this behaviour, using conventional methods to monitor reservoir performance could be misleading. Hence, a new parameter was created to make sure that reservoir performance monitoring accounts for production in a more representive way. This parameter was called Normalized Production Index.
Normalized Production Index has been used to analyse reservoir performance in Ahmadi Reservoir as it accounts for both the flush rate and the stabilized production rate of wells. This parameter helps monitor and observe reservoir performance as it effectively identifies low and high productive areas, and hence leads to better decisions during reservoir development planning.
In this study, a Normalized Production Index of more than 246 wells was considered. These wells vary in area, dip direction, trajectory, and Horizontal length. The objective was to determine the most effective way of these to maximise production in Ahmadi.
Based on the analysis done using Normalized Production Index, it was found that the average oil production for horizontal wells is more than double that of a vertical/directional well. It was also found that wells oriented in an up-dip direction of the structure are performing better than wells oriented in a down-dip direction of the structure in some areas. These conclusions were considered in managing the reservoir. Some actions were taken based on these conclusions and resulted in positive performance, which verified the effectiveness of the Normalized Production Index.
Padhy, Girija Shankar (Kuwait Oil Company) | Al-Rashidi, Tahani (Kuwait Oil Company) | Gezeeri, Taher Mohd (Kuwait Oil Company) | Shinde, Ashok (Baker Hughes, a GE Company) | Perumalla, Satya (Baker Hughes, a GE Company) | Zhou, Chong (Baker Hughes, a GE Company, presently with Petronas)
The subject upper Cretaceous carbonate formation has been characterized as a heterogeneous reservoir with varying facies and petrophysical properties. Distribution of facies strongly varied not only with depth, but also laterally across the field. Upper part of the reservoir is dominated by natural fractures whereas lower part is predominantly argillaceous with mud enrichment. In addition, presence of laminations and vugs enhanced the heterogeneity of the reservoir. Very few wells were drilled and some of them were fractured. This paper demonstrates how geomechanical and integrated reservoir characterization has shown value in well placement strategy.
Built number of well-based geomechanical models with data from all wells in order to capture reservoir heterogeneity in models. These models quantified the distribution of rock mechanical properties and pore-pressure as well as present day principle stresses. In addition, these models were integrated with geological model as well as seismic data to generate a 3D geomechanical model. After a thorough rock typing and petrophysical classification, some patterns were recognized in terms of presence of natural fractures in certain layers. However, the production contribution of these natural fractures was unclear. Upon combining all available sensitive fracture indicators, a DFN model was built and calibrated. Finally, the 3D geomechanical model combined present day in-situ stress and pore pressure magnitudes, mechanical properties of all rock facies and natural fracture occurrences at field scale. A thorough well production analysis was also performed to validate the role of natural fractures during production.
After systematic integration of diverse sub-surface data sets in 3D geomechanical model, some natural fracture subsets were identified that are optimally oriented to become critically stressed at present day stress regime. Upon further analysis, a new parameter "Index of Critically Stressed Fractures (iCSF)" was created that captured the spatial distribution of networked fracture sets in 3D model that are geomechanically favorable for fluid flow. Number of geomechanical sweetspots were identified at field scale and correlated these areas with other data. It was also recommended to stimulate wells with certain practices.
Integration of geomechanical models with production analysis and natural fracture indicators delivered value in identifying geomechanical sweetspots that have potential to flow. Distribution of these sweet spots provided a strategy for well placement as well as stimulation. In addition, this paper also exhibits logical integration of findings from geosciences and engineering disciplines to make informed decisions on well planning in order to maximize the production from challenging reservoirs.
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)
Understanding the mechanical behavior (compression, shear, or tension) of rocks plays an important role in wellbore-stability design and hydraulic-fracturing optimization. Among rock mechanical properties, strain is a critical parameter describing rock deformation under stress with respect to its original condition, yet conventional methods for strain measurement have several deficiencies. In this paper, we analyze the application of the optical method digital-image correlation (DIC) to provide detailed information regarding fracture patterns and dynamic strain development under Brazilian testing conditions. The effects of porosity, rock type, lamination, and saturation (freshwater and brine) on indirect tensile strength are also discussed.
To examine the effect of rock type, 60 samples of sandstone (Parker, Nugget, and Berea) and carbonate rocks (Winterset Limestone, Silurian Dolomite, Edwards Brown Carbonate, and Austin Chalk) were tested under dry and saturated conditions with regard to lamination angle in laminated samples. A photogrammetry system was used to monitor the samples in a noncontact manner while conducting the indirect tensile experiment. DIC depends on the photogrammetry system, which helps to visualize and examine rock-fracture patterns from the recorded images of the rock before and after deformation by assessing the strain development in samples.
The experimental results show the following.
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.
The original stress equilibrium of the formation is disturbed after borehole creation, and stress concentration is formed around the wellbore. During production, if drawdown pressure is too high, it will cause wellbore collapse and associated accidents. On the contrary, if the drawdown is too small, the production cannot meet the development needs. The ultra-deep fractured carbonate formation is tight and the in-situ stress is high. Dependent on the development of horizontal fractures and the degree of fracture filling and cementation, the distribution of UCS along the wellbore is quite different, leading to a larger variation of critical drawdown pressure. Meanwhile, different wellbore trajectories will result in different stress concertation around the wellbore and influence the critical drawdown pressure. Furthermore, UCS of the rock will be reduced when the rock is soaked in completion fluids for a long time, and the critical drawdown pressure will be reduced. In view of these problems, this paper carried out a series of core tests, and developed a model to predict the critical drawdown pressure of uncased wellbores in fractured carbonate reservoirs. The influences of completion-fluid immersion and well trajectory on critical drawdown pressure is investigated. The results show that the critical drawdown pressure of vertical wells is less than that of horizontal wells. The critical drawdown of wellbores along the minimum horizontal principal stress is larger compared with wellbores along the direction of maximum horizontal stress. Completion-fluid immersion can cause a 4-5% reduction in critical drawdown pressure.
The original stress balance is broken after drilling, and there is a stress concentration around the wellbore. When the rock strength of the borehole wall is exceeded, wellbore instability occurs. After drilling horizontally in ultra-deep carbonate reservoirs, open-hole completions are usually used. Due to the existence of a large number of low-angle natural fractures, the distribution of rock strength is uneven. Under the action of the ground stress, if the drawdown pressure is set too high, the wellbore will collapse, and the wellbore rock will clog the tubing after falling off, result in a substantial decline in output, increase operating costs; and set too low will lead to the results of production can not meet the development needs. At present, most of the studies on drawdown pressure are for sandstone reservoirs, and there is little research on the extreme drawdown pressure of ultra-deep carbonate reservoirs. Due to the large difference in physical properties between ultra-deep carbonate reservoirs and sandstone reservoirs, the study in this paper is of great significance to the rational development of the same type of carbonate reservoirs and the design of drawdown pressure.
Kozyaev, A. A. (RN-KrasnoyarskNIPIneft, LLC, RF, Krasnoyarsk) | Merzlikina, A. S. (RN-KrasnoyarskNIPIneft, LLC, RF, Krasnoyarsk) | Petrov, D. A. (RN-KrasnoyarskNIPIneft, LLC, RF, Krasnoyarsk) | Shilikov, V. V. (RN-KrasnoyarskNIPIneft, LLC, RF, Krasnoyarsk) | Tuzovskiy, A. A. (RN-KrasnoyarskNIPIneft, LLC, RF, Krasnoyarsk) | Sorokin, A. S. (Vostsibneftegas JSC, RF, Krasnoyarsk) | Kutukova, N. M. (Rosneft Oil Company, RF, Moscow) | Melnikov, R. S. (Rosneft Oil Company, RF, Moscow) | Cheverda, V. A. (Trofimuk Institute of Petroleum Geology and Geophysics, Siberian Branch of RAS, RF, Novosibirsk)
The PDF file of this paper is in Russian.
Oil and gas consumption around the world is constantly increasing. As a result, traditional deposits are depleted and make oil and gas companies pay attention to more complicated facilities. Such objects will include ‘shale oil’, deposits of high-viscosity oil and deposits associated with fractured carbonate reservoirs, one of which is given in this paper. Today, fractured carbonate reservoirs are located on the territory of the Russian Federation in Eastern Siberia, the Caucasus, the Timan-Pechora oil and gas bearing basin, and so on. The object of study in this paper is the Yurubcheno-Tokhomskoye oil and gas condensate field (UTM) located in the Krasnoyarsk Territory. The deposit is unique in its reserves and is characterized by a very complex geological structure. The main deposits of oil and gas fields are confined to the ancient Riphean, carbonate reservoir, which also complicates the study of the reservoir. In this paper the results of predicting zones with better reservoir properties is described for the Riphean carbonate vuggy-fractured reservoir using a special approach to seismic data processing to of computation scattered component of seismic waves. The paper presents the predicted fractured-vuggy reservoir characteristics (productivity and fracture trends) of a critically important impact on reservoir development. For their prediction, an integrated complex of different-scale geological and geophysical data was applied, including special well logging and testing methods and the results of special seismic data processing. The approach can be applied to will reduce the uncertainties associated with the geological structure of the deposits of oil and gas, which means that it is more effective to develop the oil and gas fields.
Постоянно увеличивающееся общемировое потребление нефти и, как следствие, истощение традиционных месторождений заставляют нефтегазовые компании обращать внимание на все более сложные объекты с точки зрения геологического строения и разработки. К такого рода объектам можно отнести нетрадиционные коллекторы, залежи высоковязкой нефти и месторождения, приуроченные к трещиноватым карбонатным резервуарам. В настоящее время трещиноватые карбонатные пласты-коллекторы на территории Российской Федерации в Восточной разрабатываются в Сибири, на Кавказе, в Тимано-Печорской нефтегазоносной провинции и других регионах. В данной статье объектом изучения является Юрубчено-Тохомское нефтегазоконденсатное месторождение, расположенное в Красноярском крае. Месторождение уникально по запасам и характеризуется очень сложным геологическим строением. Основные залежи нефти и газа приурочены к древнему рифейскому карбонатному коллектору, что также осложняет изучение резервуара. В статье рассмотрен подход к прогнозу зон улучшенных коллекторских свойств карбонатного каверново-трещинного коллектора Юрубчено-Тохомского месторождения на основе специальной обработки сейсмических данных, направленной на выделение рассеянных волн. Представлены результаты прогноза характеристик коллектора трещинно-кавернового типа, оказывающих критически важное влияние на разработку месторождения, таких как продуктивность и направление трещиноватости. Для прогноза использован комплекс разномасштабной геолого-геофизической информации, включающий специальные методы геофизических и гидродинамических исследований скважин, результаты специальной обработки сейсмической информации. Применение полученных результатов позволяет снизить неопределенность, связанную с геологическим строением месторождения, а значит более эффективно разрабатывать месторождения углеводородов.
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.