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Abstract The field is located in the southeastern part of the West Siberian basin in Novosibirsk oblast (Fig. 1). It was the first field in the basin where commercial oil was produced from the Paleozoic basement. The reservoir consists mostly of limestones and dolomites that are intensively fractured and contain numerous vugs in some zones. The reservoir properties of the matrix are generally negligible, and the production potential of wells is mostly associated with natural fractures and vugs. The presented study was our first project in Russia where a complete integrated approach was implemented to properly characterize a fractured reservoir. The approach included the following tasks: 1) Identification of fractured intervals in wells using a special technique of BKZ logs processing, 2) Spectral imaging and high-resolution inversion of the seismic data, 3) structural analysis of the field, 4) construction of the reservoir properties model, 5) construction of the fracture distribution model using the Continuous Fracture Modeling approach (CFM). A comprehensive description is available on a previous publication1. The final geologic model served as a basis to select the locations for the new wells. The new locations were proposed in the zones with the most intensive development of a network of natural fractures (according to the model). The drilling was associated with significant losses of drilling mud that was an indirect indication of presence of significantly fractured zones. The wellbore image FMS that was recorded in the well, showed a good level of correspondence between the model forecast and the actual result. The well contains interval of numerous fractures and large vugs. Eventually, the well showed a good production results and currently is one of the best producers in the field. As such, we recommend application of the described integrated approach for modeling complex fractured reservoirs in the other fields of Russian Federation. Introduction The field was discovered back in 1974 by the exploration well 2, which was drilled in the southern part of the anticline that was delineated by seismic data. Commercial flow of oil was produced from the carbonate reservoirs of the "M" horizon that represents the uppermost portion of the Paleozoic basement2. The discovery has attracted a significant attention at the time, being a first demonstration of the productive potential of West Siberian basement3. In the next few years a series of medium and small size oilfields with pre-Jurassic reservoirs have been found in the southeastern part of the basin (e.g. Archinskoe, Chkalovskoe, Urmanskoe, Gerasimovskoe, and others). In all of these fields oil was produced from the basement carbonates and weathering crust. Further investigation on Pre-Jurassic reservoir of the SE West Siberia showed that production potential is mostly related to the basement limestones that have been significantly affected with secondary processes such as dolomitization, leaching, and fracturing4. Following the initial discovery, 19 wells have been drilled in the field, and 8 of them produced commercial oil rates. The results of core investigations and well test analyses showed that the productive unit "M" consists of a complex fractured vuggy-porous type of a reservoir. A presence of opened fractures was determined as a key factor that defines productive potential of wells. General information The basement of the field consists mostly of Paleozoic carbonates that also include some layers of siliciclastic and volcanic rocks. The overall structure of the field represents a elongated anticline of an irregular shape that is located northwest of Mezhov arch. Interpretation of 3D seismic data showed that the basement strata contain numerous nearly vertical faults (Fig. 2). The faults are rarely traceable above the top of Jurassic Tyumen formation.
- Asia > Russia > Ural Federal District > Tyumen Oblast > Tyumen (0.24)
- Asia > Russia > Siberian Federal District > Novosibirsk Oblast > Novosibirsk (0.24)
- Asia > Russia > Ural Federal District > Yamalo-Nenets Autonomous Okrug > Purovsky District (0.24)
- Phanerozoic > Paleozoic (0.65)
- Phanerozoic > Mesozoic > Jurassic (0.54)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Dolomite (0.55)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Limestone (0.45)
- Geology > Structural Geology > Tectonics > Compressional Tectonics > Fold and Thrust Belt (0.45)
- Geophysics > Seismic Surveying > Surface Seismic Acquisition (0.54)
- Geophysics > Seismic Surveying > Seismic Processing (0.47)
- Asia > Russia > Ural Federal District > Khanty-Mansi Autonomous Okrug > Novosibirsk Oblast > West Siberian Basin > Maloichhskoye Field (0.99)
- Asia > Middle East > Oman > Al Wusta Governorate > Ghaba Salt Basin > Qarn Alam Field (0.99)
- Africa > Middle East > Tunisia > Kairouan Governorate > Pelagian Basin > Sidi El Kilani Concession (SLK) Permit > North Kairouan Concession > Sidi El Kilani Field > Abiod Formation (0.99)
- (2 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Faults and fracture characterization (1.00)
Abstract Horizontal well technology has been widely used in developing gas fields. Very commonly, these wells are hydraulically fractured to improve productivity in low permeability reservoirs. A previously developed method, the Distributed Volumetric Source method (DVS), was applied to horizontal gas wells with or without fractures to predict well performance. The method is flexible and can be easily applied. The method provides an effective tool to evaluate horizontal well design and well stimulation design for gas wells. In this paper, we conducted a well performance study by applying the DVS method to typical gas formations in East Texas Basin, San Juan Basin, and Appalachian Basin.. The objective is to determine the best practice to produce from horizontal gas wells. With the transient flow feature of the DVS method, well placement for multiple horizontal wells in a defined drainage area can be studied, and the limit of well spacing and wellbore length is identified. For fractured wells, well performance of a single fracture and multiple fractures are compared, and the effect of the number of fractures on productivity of the well is presented. Realizing that reservoir permeability and anisotropy ratio are the critical parameters in developing low-permeability gas fields, the effect of permeability on well performance, well placement and fracture treatment design is addressed in the paper. Introduction Development of low permeability tight gas reservoirs is becoming attractive to the energy supply problem we are facing today. The lack of flow path for gas is the biggest limitation for tight gas formations. In order to overcome that limitation, horizontal wells have been drilled, and many of them were furthermore fractured to expand the contact between the well and the formation. To study the effects of reservoir properties, well structures, and fracture treatment design, on well performance in tight gas formations, we need a simple but robust method to predict the performance of horizontal wells, with or without fractures. Horizontal well models have been presented in many literatures in the past. In order to arrive at an analytical solution, different boundary conditions have to be assumed. Thus, the models have been divided to steady-state models (Butler 2000, Furui et al 2003, and Zhu 2006) pseudo-steady state models (Babu and Odeh, 1988 and 1989), and transient flow models (Goode and Thambynayagam, 1987, Ozkan 1988 and 1989). For low permeability formations, transient flow period for a horizontal well may be significantly longer than for conventional formations. A model that can handle both transient and pseudo-steady state flow conditions will be convenient. A previous study presented a Distributed Volume Source method (Valko and Amini, 2007). The method solves the flow problem in a box-shaped reservoir with a box-shaped volumetric source. The shape of the sources is flexible, easily portraying a horizontal well with or without fractures. A smooth transition between transient and pseudo steady state flow regions was achieved by the method. The main concept of the method was to find the analytical solution for the response of a closed rectilinear system to an instantaneous volumetric source. This solution is then integrated over the time to provide the response for a continuous volumetric source. Application of the principle of superposition was used to simulate multiple fractures along a horizontal well. The method is developed for a source with uniform flux over its volume. The extension of method to cases with infinite conductivity is made possible by dividing the source into segments of uniform-flux sources. The Distributed Volumetric Source (DVS) method was extended to gas wells (Zhu et. al, 2007), and that will be the approach used in this study. Application of DVS method to Case Studies In this paper, we apply the DVS method to several typical tight gas fields in the US in different basins to study the effect of designing horizontal wells and fracture treatments on well performance. Fig. 1 shows all the tight gas basins in the USA. This paper uses data from East Texas Basin, San Juan Basin, and Appalachian Basin. It is important to point out that all of these basins have their unique characteristics, and the results and conclusions made from the study are based on each individual basin, and may not be used as general conclusion.
- North America > United States > Wyoming > Uinta Basin (0.99)
- North America > United States > West Virginia > Appalachian Basin (0.99)
- North America > United States > Virginia > Appalachian Basin (0.99)
- (23 more...)
Impacts From Fractures On Oil Recovery Mechanisms In Carbonate Rocks At Oil-Wet And Water-Wet Conditions - Visualizing Fluid Flow Across Fractures With MRI
Ferno, Martin Anders | Ersland, Geir (U. of Bergen) | Haugen, Asmund (University of Bergen) | Johannesen, Else Birkeland | Graue, Arne (U. of Bergen) | Stevens, Jim (Conocophillps) | Howard, James J. (ConocoPhillips)
Abstract The fracture/matrix transfer and fluid flow behavior in fractured carbonate rock was experimentally investigated using magnetic resonance imaging (MRI). Viscous oil-water displacements in stacked carbonate core plugs were investigated at wettability conditions ranging from strongly water-wet to moderately oil-wet. The impact of wettability and was investigated in a series of flooding experiments. The objective was to determine the impacts on fluid flow from different types of fractures at various wettability conditions. A general-purpose commercial core analysis simulator was used to simulate the flood experiments and to perform a parameter sensitivity study. The results demonstrated how capillary continuity across open fractures may be obtained when wetting phase bridges were established. A viscous component over the open fractures was provided when the wetting preference between the injected fluid and the rock surface allowed the formation of stable wetting phase bridges. The combination of high spatial resolution imaging and rapid data acquisition revealed how the transport mechanisms for oil and water were governed by the wetting affinity between the rock surface and the fluids in the fracture; both at moderately water wet conditions and at moderately oil wet conditions. Introduction Production of oil from naturally fractured reservoirs is commonly governed by co- and counter-current imbibition of water. Imbibition is dependent on wettability due to the controlling capillary forces, and waterflooding fractured reservoirs have been successful in many water-wet reservoirs. Extensive waterflooding over several years in the oil-wet field Ghaba North in Oman, however, resulted in very low oil recovery (around 2 %) as most of the oil was produced from the fractures only. Fractures generally exhibit a relatively small volume of the total porosity in fractured reservoirs (typically 1–3 %), but the fracture network is important for fluid flow due to much higher permeability and the augmentation of accessible surface in which imbibition may occur. In water-wet reservoirs, oil is produced from the matrix to the fracture system by capillary imbibition of water with subsequent oil expulsion. Capillary continuity between isolated matrix blocks is in general recognized as favorable in fractured reservoirs dominated by gravity drainage. Capillary continuity across fractures in preferentially oil-wet reservoirs may increase ultimate recovery during gas assisted gravity drainage. Capillary continuity in preferentially water-wet reservoirs increases the height of the continuous matrix column and reduces the amount of capillary trapped oil. For oil recovery in fractured reservoirs produced by viscous fluid displacement, establishing stable wetting phase bridges may contribute to added viscous pressure components over isolated matrix blocks, and thus may increase the oil recovery above the spontaneous imbibition potential. Several authors 1–3 have shown experimentally that vertical capillary continuity across fractures becomes important when gravity is the driving force. Saidi 4 (1987) introduced the idea of capillary continuity through stable liquid bridges. Labastie 5 (1990) found that the permeability of the fractured material influenced the ultimate recovery of the gravity drainage; increased permeability lead to increased oil recovery. Stones et al.6 (1992) investigated the effect of overburden pressure and the size of the contact area of the porous material across the fracture. They concluded that the size of the contact area controls the transmissibility of oil, and therefore the ability of the fracture to transport liquids across the fracture. O'Meara Jr. et al.7 (1992) investigated the film drainage along coreholder end-pieces in centrifuge capillary pressure measurements, where they argued that if the conductivity of the film was large enough, the assumption of zero capillary pressure at the outlet end of the plug could be disregarded. Firoozabadi and Markeset 8 (1994) observed capillary continuity between isolated matrix blocks by liquid film drainage along non-porous spacers placed inside the fracture, and by liquid bridging forming inside the fracture. They concluded that the film flow and the degree of fracture liquid transmissibility controlled the rate of drainage across a stacked matrix blocks.
- North America > United States > Texas (0.46)
- Asia > Middle East > Oman > Al Wusta Governorate (0.24)
Abstract "Pay now, or pay later" fits in many industries and circumstances. In well construction, ideally the operator wishes to be in a position to decide which of these alternatives is the most economic. Engineered solutions, designed to improve wellbore strength and reduce drilling non-productive time due to lost circulation, are directed at managing wellbore stresses (WSM). This fully engineered approach should include means to help prevent lost circulation as well as stop losses. Prevention of lost circulation by improving the wellbore strength is accomplished by designing and applying borehole stress treatments that increase the hoop stress around the wellbore. The technology development within the industry that led to the applications of these concepts will be discussed. Proprietary hydraulic design software (HDS) can predict the equivalent circulating density (ECD) over an interval in one module, calculate the width of a fracture that may be initiated, and select and design a proper material and particle size distribution that can efficiently prop and plug that fracture in a second module. A third module then predicts the change in rheology resulting from the addition of the specialized lost circulation materials, which then is cycled full circle back to update the ECD calculations. Contingency chemical sealant (CS) treatment applications are systems designed to react with the drilling fluid itself to create highly viscous and cohesive sealants in the wellbore that are displaced into the lost circulation fractures. Drilling-fluid-reactive systems are not dependent on temperature or pressure, thus removing a significant amount of placement uncertainty present with cross-linked systems. This combination of planning and application tools allows the operator to make decisions ahead of time during the "drilling the well on paper" phase as to which approach is the most economic - prevention (pay now) or remediation (pay later). Overview Lost circulation is one of the biggest contributors to drilling non-productive time (NPT), and it is the most difficult segment of drilling in which to make economic decisions. Estimations of economic impact in this segment vary widely, but it is safe to say that it represents a very large portion of the total non-productive expense for drilling a well. As rig rates increase, the economic impact of NPT increases as well. Therefore, any technology that reduces drilling NPT can translate into millions of dollars in reduced drilling costs. To address this problem, engineered solutions designed to improve wellbore strength and reduce drilling NPT caused by lost circulation were developed. This WSM service provides a fully engineered approach to lost circulation problems that incorporates both unique planning software and materials. Lost circulation planning includes both prevention and remediation methods. While it is critical that losses be stopped once they occur, it is equally important that they be prevented because problems prevented represent money never expended. One important part of the preventive plan is the design of "borehole stress treatments". The goal of these treatments is to increase the "hoop stress" in the near-wellbore region to improve the wellbore pressure containment ability. Wellbore Stress Theory Conventional fracturing theory predicts that lost circulation may occur when the tangential stress at the borehole surface exceeds the tensile strength of a rock. However, this conventional theory could not explain why lost circulation occurs more frequently when oil-based drilling fluids are used. Based on results from joint industry project DEA 13 conducted in the mid-1980s to answer this question, it was proposed that a stable fracture containing drilling mud with solid and gel components can exist and that lost circulation occurs when the fracture becomes unstable.1 This ultimately led to the conclusion that lost circulation mitigation could be enhanced by carrying materials in the drilling fluid that were of a proper size, concentration and type.2 The most significant result was not that lost circulation could be controlled by these treatments, but that the resistance to lost circulation (increased wellbore strength) could be enhanced significantly.3
- Europe (0.70)
- North America > United States > Texas > Dallas County (0.29)
Application of Dipole Sonic to evaluate Hydraulic Fracturing
Tellez, Oscar Mauricio (Hocol S.A.) | Casadiego, Armando (Halliburton) | Castellanos, Julian Enrique (Halliburton Energy Services Group) | Lopez, Emiliano Rodrigo (Halliburton Wireline Services) | Sorenson, Federico (Halliburton Co.) | Kessler, Calvin W. (Halliburton Energy Services Group) | Torne, Juan Pablo (Halliburton)
Abstract Hydraulic fractures are used worldwide to enhance oil and gas production. In many cases, the stimulation jobs cover multiple intervals and the evaluation of the individual zones is not a straightforward process. In Colombia (Figure 1), it was proposed to HOCOL to run the crossed dipole sonic, inside casing before and after a hydraulic fracturing job, to evaluate changes in anisotropy due to the treatment. This paper presents the complete process, including the planning and evaluation of the logging and hydraulic fracturing, and the use of this technique to evaluate hydraulic fracturing effectiveness when multiple zones are open and fractured simultaneously. The planning process includes the use of the dipole sonic to determine rock properties and the calibration process to adjust the computation of sanding potential and fracturing pressures. The use of acoustic anisotropy in cased hole proved to be an effective method for evaluating the effectiveness of the fracture treatment and for defining the characteristics of the resulting fractures. This is an innovative technique; a second application well is presented in this paper including the results. Introduction The evaluation of hydraulic fracture height has been performed by using several traditional methodologies,1-3 such as temperature logs and radioactive tracers (Figure 2). The main disadvantage of the use of temperature logs is the limited vertical resolution. The method can be improved when combined with radioactive tracers (Figure 3). A qualitative relationship has also been observed between the level of radiation and the fracture width 4-6 (Figure 4). The simultaneous use of fullwave sonic, spectral gamma ray, and temperature logs have also been investigated and documented 7. This technique showed the advantage of determining a continuous profile for the dynamic mechanical properties and the effect of the hydraulic fracture stimulation on the acoustic waveforms. The absence of shear wave information limited the use of the technique (Figure 5). The introduction of dipole sonic logging and, more recently, the crossed dipole has helped to enhance the previous method to determine the vertical extension or height of the hydraulic fracture. Vertical extension mapping is important when there is a possibility to communicate water zones or when multilayer fractures are attempted. The use of compressional and shear information to determine dynamic mechanical properties is fundamental to effective job design and to prediction of the performance of the fracture. The use of shear wave anisotropy is important in the computing of an accurate fracture height and in evaluating the efficiency of the fracture.8 Another technique recently introduced is the microseismic technology.9-10 Microseismic wavelet mapping is based on real-time monitoring, using high-resolution geophones to monitor the development and downhole shape of the fracture (Figure 6). The use of the WaveSonic® Hydraulic Fracture Height Evaluation Technique, when combined with the microseismic technology, adds value to the evaluation and planning of production enhancement. In this paper, well P-7 was fractured commingled because there is normally a significant improvement in production after the hydraulic fracture. The fracture is performed to improve communication of the reservoir to the wellbore,11 but the evaluation of individual sands is an issue when multizones are fractured together. Based on the conventional openhole logs and field experience, there were doubts about the even distribution of the sand along the different intervals open for production. In another case presented in this paper, well V-1 was fractured zone by zone and the evaluation of the fracture height was performed by using the same technique for the different fractures. The evaluation of the performance after the job was also completed using a matching technique with simulator FracproPT®, based on downhole pressure measurements taken during the job. This paper will discuss the theory behind the WaveSonic® Hydraulic Fracture Evaluation Technique, as well the operational procedures and results of this application for a particular well.
- South America > Colombia (0.70)
- North America > United States > Colorado (0.28)
- North America > United States > California (0.28)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.30)
- Geophysics > Seismic Surveying > Passive Seismic Surveying > Microseismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- South America > Colombia > Caballos Formation (0.99)
- South America > Argentina > Patagonia > Golfo San Jorge Basin (0.99)
- North America > United States > New Mexico > Permian Basin > Brushy Canyon Formation (0.99)
- (9 more...)
Abstract Fracture spacing is an important concept for characterizing flow properties of naturally fractured reservoirs, since the main function of fractures that separate matrix blocks is transporting fluids through long distances; however, the estimation of fracture spacing presents some difficulties mainly due to the fact that fractures occur at different scales, going from microfractures in thin sections and minifractures in cores, up to macrofractures in geological outcrops. The scale of interest in this work is that used in reservoir simulation, which is of the order of feet or meters. This article is based on the ideas developed in a previous paper, where a procedure to locate fractures is presented. That procedure, which makes use of resistivity data obtained through well logging, visualizes the fractures as highly conducting channels within a low conductivity medium (the rock matrix). By using a special way of data processing, it is possible to filter out data that are not associated with fractures, keeping only those data related to fractures. In this way, fracture spacing can easily be estimated. However, that procedure exhibits some uncertainties which must be overcome to make it a more reliable one. In this work, a study is made to search for an improved procedure to estimate fracture spacing. For this purpose, fractures are considered at two scales: local scale which includes micro- and minifractures present in matrix blocks, and at reservoir scale which refers to fractures separating matrix blocks. These latter fractures, called principal fractures, constitute the main fracture network, and are the subject matter of this work. Conductivity studies reveal that local scale fractures have a frequency distribution quite different from that of principal fractures. As it will be seen below, this fact facilitates establishing a procedure for estimating fracture spacing without uncertainties. To make the ideas clear, an application to a carbonate reservoir is presented. The results obtained show that the improved procedure is a simple, reliable, and practical tool for establishing the distribution of fractures along a well, from which fracture spacing can be inferred. Introduction Non sealed fractures in naturally fractured reservoirs are high conductivity channels; hence, fracture spacing is a factor that controls, to a great extent, the flow properties of such systems. In spite of its importance in areas such as hydrology, geology, geophysics, and petroleum engineering, the problem of estimating fracture spacing has not received the proper attention from researchers, and the specialized literature presents relatively few works treating in depth this theme. Among the currently used techniques for detecting fractures are well testing, core analysis, direct outcrop observation, and well logging.1–4 In this work, an improved way to determine fracture spacing is approached. In a previous paper,5 a procedure for estimating fracture spacing was developed. That procedure is based on data analysis of formation resistivity factor obtained through well logging. The fundamental consideration of the procedure is that fractures are high conductivity anomalies in a low conductivity medium (the matrix) and, consequently, the basic tool for studying fracture spacing is based on the detection of contrasts in electrical conductivity. To this end, a special analyzing process is used to distinguish between data associated with fractures and non-associated. However, such a procedure does not allow establishing with certainty a discriminating threshold between both types of data. The fractures referred to in this work are those surrounding matrix blocks. These fractures, called principal fractures, constitute the main fracture network, which has the property of transporting reservoir fluids through long distances, and eventually to the producing wells, in opposition to micro- and minifractures which act at block scale, and whose main function is to convey fluids within the matrix blocks and towards the principal fractures.
- North America > Mexico (0.29)
- North America > United States (0.29)
Abstract Waterflood management for naturally fractured reservoirs is a difficult task due to complex fluid behaviors between fracture and matrix. The streamline model is particularly useful for assessing the individual contribution of injectors to each producer accounting for inter-porosity transfer. A simulation model for naturally fractured reservoirs was developed aiming at improved waterflood management with the use of the concept of streamline-derived injection efficiency (IE). Waterflooding in the dual-porosity dual-permeability system is first modeled by the streamline approach employing the operator splitting technique to account for gravity and transfer between fracture and matrix. IEs for individual injector-producer pairs are determined from saturation profiles on streamlines in both continua after evaluating transfer effects. The model is capable of performing the reallocation of injection water to improve oil recovery from fracture and matrix. The model can also be applied readily to field-scale simulation because of rapid calculations with the streamline method. This paper describes the methodology and implementation of IE-based injection-rate control for dual-porosity dual-permeability reservoirs and demonstrates the applicability by simulation examples. Application of the method makes it possible to evaluate the dynamic efficiency of the injected water for individual injector-producer pairs. Based on the computed IEs, reallocation of the injection rate among the injectors is made so that more oil in matrix and fracture is displaced by injected water. The examples showed usefulness of the method for naturally fractured reservoirs of highly heterogeneous matrix and fracture properties. Introduction Thiele and Batycky 1 proposed a novel approach to predict well rate targets of injectors and producers for improved waterflood management. Their approach is based on streamline simulation and the injection efficiency (IE) for injectors and injector-producer pairs. An advantageous feature of the streamline simulation is that the total rate and the phase rates are readily available on individual streamlines.2 The IE is defined as a ratio of offset oil production rate to water injection rate, and can be evaluated for each injector connected to multiple producers and each injector-producer pair, as well as for the total field. Assuming the fixed well status in mature fields with a constraint of total available water, Thiele and Batycky demonstrated improved waterfloods by reallocating injection water from low-efficiency to high-efficiency injectors with the aid of IEs. Waterflooding is also an effective process in naturally fractured reservoirs (NFRs) to recover oil in both fracture and matrix. Waterflood management in NFRs, however, is more difficult due to complex flow mechanisms such as high permeability contrasts of fracture and matrix, non-uniform developments of fractures, and fluid transport between fracture and matrix. This paper extends the IE approach of Thiele and Batycky 1 to NFRs. The streamline-based method proved to be applicable for NFR simulation by assuming the dual-porosity model 3,4 or the dual-porosity dual-permeability (DPDP) mode l5. In this paper, a DPDP model developed previously 6 is utilized for implementing the system of improved waterflood management. The formulation and verification of our model is first described, and then detailed are implementation of the Thiele and Batycky approach in the DPDP model and example applications. Effects of injection water reallocation on oil production are evaluated with forecasting simulation. Thus, the approach is meaningful only if the reservoir model has been history-matched satisfactorily, as Thiele and Batycky 1 indicated.
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.59)
Abstract The gravity drainage and oil reinfiltration phenomena that occur in the gas cap zone of naturally fractured reservoirs are studied through single porosity refined grid simulations. A stack of initially oil-saturated matrix blocks in presence of connate water surrounded by gas-saturated fractures is considered; gas is provided at the top of the stack at a constant pressure under gravity-capillary dominated flow conditions. An in-house reservoir simulator, SIMPUMA-FRAC, and two other commercial simulators were used to run the numerical experiments; the three simulators gave basically the same results. Gravity drainage and oil reinfiltration rates, along with average fluid saturations, were computed in the stack of matrix blocks through time. Pseudo functions for oil reinfiltration and gravity drainage were developed and considered in a revised formulation of the dual-porosity flow equations used in fractured reservoir simulation. The modified dual-porosity equations were implemented in SIMPUMA-FRAC,1,18 and solutions were verified, with good results, against those obtained from the equivalent single porosity refined grid simulations. Same simulations, considering gravity drainage and oil reinfiltration phenomena, were attempted to run in the two other commercial simulators, in their dual-porosity mode and using available options. Results obtained were different among them and significantly different from those obtained from SIMPUMA-FRAC. Introduction One of the most important aspects in the numerical simulation of fractured reservoir is the description of the processes that occur during the rock matrix-fracture fluid exchange and the connection with the fractured network. This description was initially done in a simplified manner and therefore incomplete.2,3 Experiments, theoretical and numerical studies 3–6 have allowed to understand there are mechanisms and phenomena such as oil reinfiltritation or oil imbibition and capillary continuity between matrix blocks that were not taken into account with sufficient detail in the original dual porosity formulations to model them properly and that modify significantly the oil production forecast and the ultimate recovery in a naturally fractured reservoir. The main idea of this paper is to study in further detail the oil reinfiltration phenomenon that occur in the gas invaded zone (gas cap zone) in NFR and to evaluate its modeling to implement it in a dual porosity numerical simulator. Considering the reservoir to be a stack of matrix blocks (sugar cubes) according to the Warren and Root 7 conceptual dual porosity model, the oil reinfiltration occurs when the oil confined in the upper blocks is expelled out of matrix blocks thru fractures and it reinfiltrates in the blocks below. This block to block oil flow occurs mainly because of the competition of the capillary and viscous forces. The study was divided in two parts, firstly using a single porosity simulator a fine grid was built in the space occupied by the stack of matrix blocks and fractures allocating the particular characteristics and properties of each medium to the different portions that these systems occupy in the grid. The phenomena that occur during the numerical experiment were studied. The capillary forces act only on the matrix blocks being zero in the fractures and the viscous forces are canceled out through the introduction of a very low gas injection rate through the top face of the stack; a flow process driven by capillary and gravitational forces only is established in this fashion. 8,9 In the fine grid simulation average gas and oil saturations are computed as time goes by for each one of the matrix blocks in the stack. Drainage and reinfiltration rates are computed through each one of the matrix block faces and their dependencies on the matrix block average gas saturations are established. Then the pseudo functions that are required in the modified dual porosity formulation are calculated. Secondly, using the modified dual porosity simulator SIMPUMA-FRAC, a coarse grid is built of the same dimensions of the single porosity fine grid and the gravity drainage is simulated by using the matrix-fracture transfer pseudo functions that had been previously generated. Hence, the modified dual porosity simulator should reproduce the average behavior observed in the fine grid for the stack of blocks in the single porosity model.
- North America > United States (0.68)
- North America > Mexico (0.46)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
Abstract In-situ combustion is a thermal recovery method used for enhanced heavy oil recovery. In this process air is injected to the reservoir in order to achieve ignition and to maintain the combustion front while pushing the heated oil toward producing wells. This study deals with the feasibility of in-situ combustion process in fractured heavy oil reservoirs. A one dimensional, three-phase in-situ combustion simulator with six components, two cracking and three oxidation reactions is used in this study. Primarily, a conventional simulation model based on experimental data available in the literature was constructed and sensitivity study tests were performed. In the second part of this project, the conventional model was modified to a fractured model and various parameters and mechanisms such as oil recovery factor, average temperature of the system, cumulative oil and water production, diffusion, and wet combustion process were investigated. Results indicate the importance of grid block size, injection rates, kinetic models, and equilibrium ratios of heavy and light oil components on simulation process. Simulation results indicate that the optimum water/oil ratio leads to an increase in the amount of oil recovery and a reduction in the amount of air to be injected. The study presented here with its promising outcome is a pre-requisite to justify laboratory experimental investigation of the in-situ combustion process in naturally fractured reservoirs. Introduction In-situ combustion is a complex Enhanced Oil Recovery (EOR) process normally suitable for medium to heavy crude oils. The process involves all the complexity associated to the multi-phase fluid flow through porous media with chemical and physical transition of the crude oil components under high temperature and high pressure conditions. The process becomes further complex when it is aimed for the heavy oil recovery from naturally fractured reservoirs. Because of the complexity involved, its field application has been limited and difficult to handle. With the inevitable peak oil in horizon and the rising global demand for crude oil, renewal interest has been generated toward heavy oil reserves that thermal recovery techniques are mostly suited for their recovery. Conventional production methods are not suitable for heavy oil reservoirs and technological advancements are needed to make heavy oil deposits a more viable resource. Advanced technologies are essential to enable production, transportation, and refining of heavy crude oils at a reasonable cost. This is essential to make the share of heavy oil production to levels greater than the current 10% of overall crude oil production. There are several giant heavy oil reserves in the world such as heavy oil deposits belt encountered in a 700 kilometers long by 60 kilometers wide along the Orinoco River in eastern Venezuela. The middle east region has 36% of the world's heavy oil deposits followed by the United States with 11% and Russia with 6%. Table 1 presents the major deposits of heavy oil and tar sands in the world. In-Situ Combustion Process To appreciate the need for further investigation of the process, it seems useful to make a brief review of the process and the improvements achieved over a period of more than half a century. In-situ combustion is a thermal recovery technique in which a small fraction of the heavy end of the crude oil is burned to create the heat needed to raise the temperature of the reservoir and the crude. Since the viscosity of the crude oil reduces exponentially with temperature, the process helps the crude oil to flow more readily from the rock into the production well. Upgrading of crude oil because of thermal and catalytic cracking is another major phenomenon occurring during the process that facilitates the flow of crude oil through the rock. In-situ combustion has gone through a wide range of variations and improvements due to the needs encountered in its application to various types of reservoirs and crude oils involved.
- Asia (1.00)
- North America > United States > Texas (0.46)
- North America > Canada > Alberta (0.29)
Abstract This study presents a parametric study to evaluate the performance of the vertical and horizontal wellbores with and without fractures and frac-and-packs, and multi-lateral horizontal wells with various laterals and branches for different carbonate reservoir characteristics. Series of three phase and three dimensional mathematical models are prepared to simulate the naturally fractured carbonate reservoir performance under various scenarios. A novel approach is utilized to effectively simulate the performance of the hydraulic fractures by considering the induced fractures as a boundary condition for the reservoir system. Potential stimulation and completion techniques are compared by three measures: Effective normalized cumulative hydrocarbon production, volume fraction of the influenced reservoir domain, and normalized damage ratio. Performance and economical analyses are carried out, indicating that the completion methods covering more reservoir volume and effectively connecting the natural fractures to the wellbore yield a higher efficiency. It is demonstrated that the effectiveness of all the stimulation techniques strongly depends on the angle by which the natural fractures are intersected throughout the reservoir, and the normalized damage ratio caused by the completion and stimulation technique. The economical analysis and evaluation help determine the best completion and stimulation technique. Introduction A large fraction of the world's hydrocarbon reservoirs are naturally fractured. Some of the southern United States sandstone and carbonate reservoirs, majority of the Middle-East carbonate oil reservoirs, a high percentage of the shale-gas reservoirs, and coalbed-methane gas reservoirs are some examples of the naturally fractured reservoirs. Naturally fractured reservoirs are usually composed of a matrix of very low permeability surrounded by a network of high permeability and low porosity fractures. The high porosity matrix stores a large fraction of the hydrocarbon and the high permeability fractures act as channels for hydrocarbon transfer within the reservoir toward the production wells. Natural fractures in a reservoir rock may have been induced from the movements of the earth's internal layers (tectonic fractures), little changes in the earth crust over previous geological time (regional fractures), bulk volume reduction due to in-situ thermal, chemical, and mineral alterations (contraction fractures), and by other mechanisms. Features of natural fractures in petroleum reservoirs, including fracture porosity, permeability, orientation, and extension, vary depending upon the reservoir formation depth, geological history, and physical and chemical characteristics. Naturally fractured reservoirs are usually anisotropic and heterogeneous having different horizontal to vertical permeability ratios. Productivity of a naturally fractured reservoir depends strongly on the permeability, size, distribution, and extension of fractures throughout the matrix in each direction. Therefore, selecting proper stimulation and completion techniques to maximize hydrocarbon production and sustain economic productivity and avoid reservoir formation damage is of great importance. Jahediesfanjani and Civan studied the effect of the various completion and stimulation techniques including the vertical, horizontal, multi-lateral wells with fractures in different quantity, size, conductivity, and type on the coalbed productivity of the methane gas reservoirs characterized as naturally fractured reservoirs. The parametric studies showed that the productivity of any stimulation technique in naturally fractured gas reservoirs is depend on the horizontal to vertical permeability ratio and the reservoir formation special characteristics. However, the mechanism of fluid transfer and production is different in petroleum reservoirs than coalbed methane reservoirs. The former usually contains a three phase system of oil, gas, and water.
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.68)
- Geology > Petroleum Play Type > Unconventional Play > Fractured Carbonate Reservoir Play (0.60)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.54)