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Abstract Detection and characterization of fractures in rock is important in many cases for the development of energy resources such as geothermal energy and petroleum. To this end, the effect of frequency on resistivity as a function of water saturation has been studied in rocks with and without fractures. Different rocks (Berea sandstone, greywacke from The Geysers geothermal reservoir) were used in this study. It was found that the effect of frequency on resistivity is different in rocks with and without fractures, especially in the range of low water saturation. The validity of the Archie equation depends on the existence of fractures, frequency, and the range of water saturation. Introduction Increasing attention has been paid on the development of hydrocarbon resources in low permeability reservoirs with heterogeneity or significant fracture density. The same is true for the geothermal resources. For low permeability reservoirs with a low density of fractures, hydraulic stimulation is the primary means of creating additional fractures to allow the recovery of the energy resources (oil, gas, or heat) at economic rates. The detection and characterization of fractures is crucial in many cases for the development of these energy resources. We speculated that the study on the resistivity measured in rocks with and without fractures at different frequencies might be helpful to find ideas and methods for detecting fractures in rocks. The frequency dependence of electrical and dielectrical properties of rock partially saturated with water has been reported by many researchers (Knight and Nur, 1987; Adisoemarta and Morriss, 1992; Börner, 1997; Bona et al. 2001; Haugland, 2005). Knight and Nur (1987) collected impedance data for eight sandstones at various levels of water saturation in the frequency range of 5 Hz to 4 MHz. They found that the real component of dielectric constant of all samples at all levels of saturation showed a clear power-law dependence upon frequency. Comparing the data from the eight sandstone samples at a water saturation of 36%, the magnitude of the frequency dependence was proportional to the surface area-to-volume ratio of the pore space of the sandstones. Adisoemarta and Morriss (1992) investigated the electrical properties of swelling shales across a wide frequency range from 10 Hz to 1.3 GHz. They found that the resistivity of different types of shales decreases with the increase in frequency from 10 Hz to about 10 KHz and stays almost constant when the frequency is above 10 KHz. The experimental data presented by Adisoemarta and Morriss (1992) also demonstrated that the effect of the frequency on the resistivity was more significant at lower water saturations than at greater water saturations. Bona et al. (2001) conducted experimental and theoretical studies to investigate the effect of rock wettability on the electrical response of water- and oil-saturated core samples in a wide frequency band. According to the experimental results reported by Bona et al. (2001), in the low-frequency range, the real and the imaginary components of dielectric constant decrease with increasing frequency. Charge transport was the dominant mechanism in this low frequency region. At higher frequencies, the real and the imaginary components of dielectric were not monotonically proportional to frequency. The charge transport no longer dominated the dielectric response of the samples and the Maxwell-Wagner effect began to come into play. In this study, the effect of frequency on resistivity as a function of water saturation was studied in rocks with different porosity, permeability, and lithology. Experiments The apparatus used to measure the resistivity in the core samples as a function of saturation is shown in Fig. 1. The main devices were a balance with reading accuracy of 0.01 g (Model 1600 from Satorius) and an RCL meter (Model 1715 by QuadTech) to measure resistivity data. The balance was used to measure the amount of water evaporated as a function of time and the data were used to calculate the water saturation in the core.
- North America > United States > West Virginia (0.26)
- North America > United States > Pennsylvania (0.26)
- North America > United States > Ohio (0.26)
- North America > United States > Kentucky (0.26)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.91)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.45)
- Energy > Oil & Gas > Upstream (1.00)
- Energy > Renewable > Geothermal > Geothermal Resource (0.70)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Non-Traditional Resources > Geothermal resources (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Faults and fracture characterization (0.87)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (0.78)
Abstract This paper presents an overview of the subsurface economic and technical issues involved in developing a Southern North Sea (SNS) tight gas field using hydraulic fracturing. The paper investigates different kinds of wells (vertical vs. horizontal) and different completions; fracture spacing, fracture orientations (longitudinal vs. transverse). The investigation was performed using a range of different reservoir qualities with appropriate completion and stimulation designs. Production and Net Present Value (NPV) estimates were developed for the different scenarios for qualitative and quantitative evaluation. The result is a generic strategy to evaluate a Field Development Plan (FDP) using hydraulically fractured horizontal wells. The paper concludes with general guidelines on what type of recoveries are possible using different completion and stimulation solutions in situations with different kh distributions. The guidelines will help in initial screening of prospects to determine whether the tight gas reservoirs have significant potential for economic development. The latter is also a function of the actual development costs of pipelines and platforms, which is different for different companies and different locations. This paper also demonstrates why stimulation considerations should be put on the agenda early on in the construction of an FDP. Introduction The majority of the SNS gas fields produce from the Rotliegend sandstone formation that is of Permian age with aeolian and fluvial depositional environments. Over the past decades several completion, stimulation and production approaches have been executed in the SNS 1. In recent years the focus for new developments and redevelopments, both plans and executions, has been on horizontal wells with multiple hydraulic fractures. Execution thus far has been complicated by the lack of available stimulation equipment for the SNS. Recently this appears to have become less of an issue, with several service companies implementing and offering skid based or otherwise portable fracturing spreads for deployment on to temporary platforms or suitable temporary boats. As many before us have presented, the definition of tight gas is a purely economic question. The main purpose and value of hydraulic fracturing in a low permeability formation is to accelerate production, see Figure 1 for a generic example. This acceleration improves the NPV of the complete investment dramatically and therewith hydraulic fracturing directly impacts the definition of "tight gas" itself for a given economic environment. The reservoir quality range investigated in this study includes permeability values covering the range of what is considered, in current day perspective, as "tight-gas" in the North Sea i.e. 0.5 mD, 0.1 mD and 0.01 mD. The reservoir layering was chosen to represent a typical Rotliegend field that has a laminated sand-shale sequence (Figure 2). A range of different net/gross ratios (NGR) scenarios was also examined, to demonstrate the effect that fracture height growth can have on recovery in a laminated reservoir with several non-pay intervals as well as the impact of uncertainty in net pay determination on project economics. The reservoir pressure gradient and stress situations were selected to cover common values for the SNS. A horizontal well with a horizontal section of 3000 feet was investigated, with a range of different fracture spacings and two different fracture orientations. The production simulations performed assumed a single phase (dry gas). Table 1 shows the basic reservoir parameters used in the study.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.89)
- Geology > Sedimentary Geology > Depositional Environment > Continental Environment > Fluvial Environment (0.54)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Tight gas (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Management > Asset and Portfolio Management > Field development optimization and planning (1.00)
Abstract Gravity is a major recovery mechanism of naturally fractured reservoirs, where fracture gas drains matrix oil until equilibrium is reached with the capillary forces (wrt fluid densities, matrix gas capillary pressure and block height). The challenge of modelling gravity drainage in dual-medium simulation is to match the final maximum recovery, using integrated pseudo-capillary pressure curve, and the correct recovery kinetics. The paper suggests an approach to improve the simulation of the recovery kinetics in gravity drainage by dividing the matrix block for the fluid transfer function in two specific parts: saturation front part (SFP) and initial state part (ISP). As the invading gas enters the matrix the SFP and ISP areas increase and decrease respectively, until the final recovery is reached at equilibrium point. The contributions from each part are summed up to equal a mass conservation equation at each time step for each matrix cell. Properties of SFP depend on the invading fluid saturation and ISP hold the initial state properties, hence its name. This SubFace formulation can be implemented in flow simulator for reservoirs exhibiting a dual-medium behaviour. Our SubFace Transfer Function approach (SF), performs well versus not only conventional transfer functions (Kazemi, Gilman), but also versus two improved ones: Quandalle-Sabathier, and Lu-Blunt (non-Warren-Root General Transfer Function) in matching the results of fine-grid single-medium models under various parameters (capillary pressure, matrix shape and mobility). We also tested SF in mixed-wet water-oil system to assess its capability of modelling gravity and capillary imbibition. This new formulation improves dual-medium simulations of fractured reservoirs with an accurate representation of matrix-fracture exchanges, and better reserves assessment and reservoir management. Introduction For a large class of fractured reservoirs produced through multiphase production mechanisms, the standard flow simulators cannot capture the two-timescale flow behaviour. The dual-medium approach is a compromise between a fully upscaled representation, where matrix and fracture properties are lumped together, and an explicit modelling of both domains which would lead to huge simulation models. Between the two domains overlapping each other, between fracture (flowing domain) and matrix (stagnant domain) the flow exchanges are usually represented by a transfer function (Barenblatt et al. 1960, Warren and Root 1963, Kazemi et al. 1976). During the last three decades, various formulations have been proposed, and we reviewed some of them in Abushaikha et al. (2008a). One condition to ensure reliable analysis and prediction of naturally fractured reservoir performance is to define such transfer functions (TF) that simulate the behaviour of the main recovery mechanisms occurring between the two media correctly, in particular for capillary and gravity drainage/ imbibition mechanisms. In Abushaikha et al. (2008a) we assessed and compared the usual Kazemi (1976) approach, the improved Gilman et al (1983) formulation for gravity, the Quandalle et al (1989) splitting method, which improved the simulation of mixed wet systems in particular and the Lu et al (2006, 2007, 2008) generalised transfer function (GTF), which adopts an idea from Zimmerman et al. (1993) and Mathias et al (2003). Since then Lu (2008) proposed a gravity corrected variation of the GTF, which has been used in this study to benchmark our approach. In order to face the challenge of a more accurate representation of both early and late time, which is the weak point of any Warren-Root-based TF, we suggested a way to eliminate the semi-steady state approach in matrix capillary imbibition (Abushaikha, 2008b). The so-called SubFace TF depends on time, space and two recovery periods (early and late time).
- North America > United States > Texas (0.28)
- Europe (0.28)
- Asia (0.28)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Data Science & Engineering Analytics > Information Management and Systems (1.00)
Abstract During the primary production of fractured reservoir most of oil is produced from fractures and a lot of oil remains in matrix. Trapped oil in the matrix can be recovered by gas injection by activating gravity drainage mechanism. In addition there is a big impact of molecular diffusion of oil and gas in total oil recovery from fractured reservoir. The experimental work can by used to model this mechanism in combination of numerical simulator to investigate this phenomenon more accurately. A fully compositional model has been applied to a numerical experiment in literature to investigate the drainage of CO2 from a core with artificial fractures and the effect of molecular diffusion included. The same study has been applied for a synthetic fractured reservoir model to investigate the effect of CO2 injection in oil recovery mechanism in the field scale. In this work we found that at early stage we have oil swelling and gravity drainage followed by a slow extraction mechanism which recovers the intermediate and heavy components from the residual oil. The combined effect of diffusion and gravity suggests that application of the oil and gas diffusion coefficients is critical in any field scale simulation of a fractured reservoir and the correct diffusion coefficients should be applied. A lot of oil reservoirs in the world are fractured and with primary recovery we can produce maximum 30 % of original oil in place therefore we need to have an accurate observation of secondary and tertiary oil recovery in these reservoirs. The understanding of oil recovery mechanism also is crucial for reservoir management especially when developing field management plans. A low miscibility-pressure requirement often is a significant advantage of CO2-miscible flooding. This process could have significant future application in areas with economical CO2 supplies from natural deposits or surface sources. Introduction A lot of oil remains in matrix blocks in fractured reservoir after primary recovery of reservoir. For recovering substantial quantities of that oil trapped in the matrix block gas injection is one method which will activate the gravity drainage mechanism in reservoir. The density difference between gas in the fracture and oil in the matrix causes production of oil until gravitational forces are equalized by capillary forces. However, in many cases like low permeability of matrix, small size matrix blocks and high capillary pressure, gravity drainage may be very low or ineffective but still one solution to recover matrix oil is to inject a dry gas. Thus, mass transfer takes place between the gas in the fracture and the gas/oil system saturating the matrix blocks. The theory of fluid flow in fractured porous media developed in the 1960's by Barrenblatt et al., (1960). Warren and Root (1963) introduced the concept of dual-porosity models into petroleum reservoir engineering. Since that time, numerical modeling of naturally fractured reservoirs using dual-porosity models has been the subject of numerous investigations. However it's difficult to present imbibition and gravity drainage properly in the dual-porosity and dual-permeability formulations most commonly used in industry to model fractured systems. In some formulations, attempts have been made to represent correctly the physical behavior of process by considering a gravity term, and assuming a simplified fluid distribution in the matrix blocks. Using a gas phase for improving oil recovery in the fractured reservoirs, one of these phenomena creates in the system: 1- first contact miscibility, 2- vaporization mechanism, 3- condensation mechanism or 4- condensation/vaporization mechanism.
- Europe (1.00)
- North America > United States (0.93)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- (2 more...)
Abstract The Schoenkirchen Tief reservoir is located in the Vienna Basin. The reservoir contained 19 mn m oil originally in place. The current recovery factor after 46 years of production is 59 %. The field was produced by water injection. The wells, located at the crest of the high relief structure are exhibiting a high water cut. 2006–2008, a comprehensive study was performed to optimise the future development of the field. The study showed that this field can be used for high performance Underground Gas Storage. Due to gas/oil gravity drainage, oil will be mobilised and can be produced resulting in enhanced oil recovery. The field development of this fractured dolomite reservoir can be optimised by using vertical dewatering wells. Completing the vertical wells far down in the structure results in minimising gas coning and fast build up of the working volume of gas. To reduce water handling costs, these water wells will produce the water out of the reservoir into a highly permeable aquifer located above the reservoir. This means, no water will be produced to surface. The drainage of oil in the matrix of this dual-porosity dual-permeability reservoir model is lagging behind the downward movement of the gas/oil contact in the fractures in this high relief reservoir. Once the oil rim reached the original oil/water contact in the matrix, horizontal wells can be drilled to produce additional oil. Processes which had to be considered in this field development are the fracture-matrix interaction, hysteresis and fluctuations of the oil rim in the fractures during the gas cycles. Introduction The Schönkirchen Tief Field consists of dolostones with high permeabilities. Due to the depth, size and permeabilities of the reservoir, it is seen as a good candidate for Underground Gas Storage (UGS). The field is located about 20 km northeast of Vienna in the proximity of large gas pipelines. An integrated study has been performed to determine the suitability of using this field for UGS (de Kok & Clemens 2008). The field initially contained oil and was water flooded from the bottom upwards for the last 46 years. Another aim of the study was to investigate if oil can be mobilised by gas injection due to the difference in residual oil versus water and residual oil versus gas. To optimise the planned UGS development, a combination of vertical and horizontal wells was evaluated. To minimise injection costs, water injection into another horizon was covered in the study. In the next paragraph, the geological setting of the field is described followed by the production history. Subsequently, history matching the simulation model and simulation of conversion of the field into UGS is covered.
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.56)
- Europe > Austria > Vienna > Vienna Basin (0.99)
- Europe > Austria > Lower Austria > Vienna Basin (0.99)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > Natural gas storage (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
Integrated Approach To Identify Fault Pattern And Fracture Corridors In A Matured Field
Thakur, Ram Kumar (Kuwait Gulf Oil Co) | Wani, Mohammad Rafiq (Kuwait Gulf Oil Co) | Chouhdary, muhammad Akram (Kuwait Gulf Oil Co) | Rashidi, Hussain (Kuwait Gulf Oil Co) | Al-Hajri, Mubarak (Kuwait Gulf Oil Co)
Abstract The development of low reservoir pressure pockets and deteriorating reservoir properties in southern parts of the Ratawi Oolite reservoir has revealed the complex nature of fault and fracture network in Wafra field. These faults could not be observed directly on 3D seismic data due to the lack of perceptible change in seismic trace along stratigraphic boundary. This problem has been resolved with innovative fault/fracture characterization technique synthesizing seismic attributes, well information and reservoir behaviour. The instantaneous phase attribute volume derived from reprocessed 3D seismic data highlighted the lateral impedance contrast to provide better resolution at discontinuities to detect even subtle change in dip and azimuth to identify fault traces along seismic sections. The alignment of fault pattern was mapped with variance cube, sum of amplitude and edge detection attributes along Ratawi Oolite Top seismic reflector. The localized nature of the effect of injection wells to improve reservoir pressure in the Ratawi Oolite reservoir in the southern portion of the field has stressed upon the presence of fault compartments and fracture corridors in the vicinity of these drilled wells. The envisaged fracture corridors were mapped integrating seismic attributes such as coherency, attenuation time with interpretation of rose diagram, Formation Micro Image and core data. The heterogeneity in reservoir behaviour, complex nature of fault and associated fracture network was further confirmed by impedance slice at Ratawi Oolite level derived using post stack seismic inversion technique. The estimated depth map with fault and fracture corridors at the Top Ratawi Oolite reservoir, generated using interpreted seismic time, modelled stacking velocity provided a guide to plan development and delineation wells in this field. This paper presents an integrated approach to identify alignment of fault and fracture corridors to plan for optimum location of injectors/development wells to optimize recovery in a matured field.
- Geology > Structural Geology > Fault (0.92)
- Geology > Geological Subdiscipline > Geomechanics (0.68)
- Geophysics > Seismic Surveying > Seismic Interpretation (1.00)
- Geophysics > Seismic Surveying > Seismic Processing > Seismic Migration (0.89)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling > Seismic Inversion (0.55)
- Asia > Middle East > Saudi Arabia > Saudi Arabia - Kuwait Neutral Zone ("Partitioned Zone") > Arabian Basin > Widyan Basin > Wafra Joint Operations Block > Wafra Field (0.99)
- Asia > Middle East > Kuwait > Saudi Arabia - Kuwait Neutral Zone ("Partitioned Zone") > Arabian Basin > Widyan Basin > Wafra Joint Operations Block > Wafra Field (0.99)
- Asia > Middle East > Kuwait > Ahmadi Governorate > Arabian Basin > Widyan Basin > Ratawi Formation (0.99)
Abstract The effect of a pre-existing natural fracture on the extension of a hydraulically induced fracture has been modeled based on poro-elastic behavior. The approach of Warpiniski and Teufel was adopted to evaluate the fracture propagation that would occur after an induced fracture intersects an existing natural fracture. This two dimensional numerical model will simulate the interaction between an induced propagating fracture and natural fracture. The model departs radically from current models in that poro-elastic behavior is not used, uniform pressure inside the natural fracture was used in practice this is not true and effect of fracture toughness ignored. A modified leak-off model for intersecting fracture based on poro-elasticity is introduced as the leak-off is increased in the intersection. Besides these previous model used startup solution using PKN model. In this model a triple system of wellbore-fracture-formation is considered and the fracture will initiate first then propagate some extent then interact with natural fracture. A poro-elastic solution for the stresses in the interaction zone has been used as a basis for hydraulic/natural fracture interaction criteria. The criteria compares favorably with the experimental results. Comparison of the numerical results with experimental results has shown that the main effect of the natural fractures is the width constriction that occurs when the induced fracture propagates into the natural fracture. Numerical and experimental studies for such propagation indicate a near wellbore width and effective length reduction due to the additional normal stress acting on the plane of the induced fracture.
- North America > United States (0.28)
- Europe > Norway > Norwegian Sea (0.24)
Abstract A study was carried out to determine the geomechanical effects of polymer flooding in an unconsolidated sand reservoir. The work involved laboratory-scale polymer injections in unconsolidated sand blocks to identify the injectivity mechanisms, numerical analyses for fracture prediction, and geomechanical modeling of the formation to examine the potential of shear failure and containment loss during flooding. Laboratory tests under polyaxial conditions indicate that near-wellbore fracturing and permeability increase in unconsolidated sands occurs at net injection pressures limited to 2.0 MPa. These findings were applied to fracture modeling. Geomechanical modeling suggests large-scale shear failure in the sand and in the bounding shale during polymer flooding. These are expected to affect both the fracture containment and the vertical-hole integrity. Finally, fracture predictions underscore the importance of the geomechanical considerations on determining the fracture dimensions and containment. Sensitivity analyses also point to the significance of bounding several key parameters for fracture prediction. These include sand-shale stress contrast, fluid quality and TSS content, fluid rheology and effective viscosity in the formation, and the filtercake properties in the presence of polymer. This paper is intended to provide a geomechanical perspective on the generally complex problem of polymer flooding in unconsolidated formations containing viscous oil. The work also offers some insights into the critical issues that must be examined in such situations to avoid catastrophic failures, and highlights the existing technological gaps in the current predictive capabilities. Introduction Some of the unconsolidated sand formations both onshore and offshore contain high viscosity oil and might be considered for polymer flooding to improve recovery. Flooding in unconsolidated sand could lead to "fracture" propagation. Although such formations typically have high permeability in the order of several Darcies, the minute quantities of impurity and solids present in the injection fluid can plug the sand face over time and lead to fracturing, if the injection rate is to be maintained [1]. Even in the absence of any fines and solids contaminants in the fluid, the high in-situ oil viscosity and low polymer mobility could instigate fracture propagation if the injection rate is sufficiently large. The principal concerns about fracturing during flooding pertain to length control and vertical containment. The fracture length must be limited to avoid interception with the production wells. Moreover, the fracture half-length must be typically less than one-third of the distance between the injector and producer to obtain good areal sweep and to ensure that fracture growth will not be detrimental to the pattern sweep, regardless of the principal horizontal stress orientation in the reservoir. For unconsolidated sands, there are currently no theoretically sound techniques to predict the fracture geometry and whether or not a fracture would be contained within the reservoir. Since the stress contrast between the sands and shales in unconsolidated formations is typically small, determination of containment requires a better understanding of the propagation mechanisms at the interface.
- Europe (0.88)
- North America > United States > Texas (0.46)
- North America > United States > Colorado (0.28)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.86)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Block 23/27 > op (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Block 23/22a > op (0.99)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Abstract The co-injection of CO2 and a CO2-foaming agent to form stable CO2-foam has been found to improve the sweep efficiency during CO2-foam processes in carbonates reservoirs. However, only a few studies of CO2-foam transport in fractured rock have been reported. In fractured chalk reservoirs with low matrix permeability, the aqueous CO2-foaming agent solution will flow mainly through the fractures. The total retention in the reservoir will depend on how much of the matrix that is contacted by the foaming agent solution during the project period and therefore its transport rate into the matrix. This paper presents results from a series of static and flow-through experiments carried out to investigate the transport and retention phenomena of CO2-foaming agents in fractured chalk models at 55°C. Fractured chalk models with 100% water-saturation and at residual oil saturation after water flooding were used. In the static experiments, the fractured model was created by transferring core plugs with different diameters into steel cells with an annulus space around the plugs. The fracture volume was filled with foaming agent solutions with different initial concentrations. The experiments were carried out in parallel with liquid samples regularly taken out from the fracture above the plugs and analyzed for the foaming agent concentration. The experiments were monitored until the concentrations in the fractures reached a plateau. At specific and constant concentrations of the foaming agent in the fractures, the plugs were demounted and samples drilled out from the outer, middle and centre portions. These samples were analyzed for foaming agent concentration to determine its transport rate into the matrix. Results indicate that the transport of the foaming agent decreases towards the centre of the plugs with 100% water-saturation and at residual oil saturation after water flooding. Modeling of the static experiments using the commercial simulator STARS were carried out to determine the transport rate for the foaming agent. A good match between experimental and modeling results was obtained. In the flow-through retention experiments, the fractured model was created by drilling a concentric hole through the center of the plug. The hole simulating an artificial fracture was filled with glass beads of different dimensions. Fractured models with different effective permeability were flooded with the foaming agent solution until the inlet and the outlet concentrations were the same at stable differential pressures. Results show that the retention of foaming agent both in the absence and presence of oil to be slower in fractured models than in homogeneous models with viscous flooding of the rock. Introduction One of the prevalent enhanced oil recovery (EOR) techniques involves the injection of gases such as steam, carbon dioxide, enriched hydrocarbons, and nitrogen into the oil reservoirs to improve oil recovery. However, at most reservoir pressures and temperatures, these gases are usually less viscous than water and oil and they often channel through high permeability regions or rise to the top of the reservoir by gravity segregation (Apaydin and Kovscek, 2001; Panahi, 2004). For example, inspite of the favorable characteristics CO2 has for achieving dynamic miscibility with oil under most reservoir conditions, CO2 flooding processes frequently experiences poor sweep efficiency due its high mobility (Grigg and Chang, 1999). This is mainly due to the low viscosity and density of CO2 compared to that of crude oil which leads to gravity override, channeling and viscous fingering (Nguyen et al. 2000). As a result, sweep efficiency decreases and significant amounts of oil are left behind (Apaydin and Kovseck, 2001).
- Europe (1.00)
- North America > United States (0.47)
- Asia > Middle East > Turkey (0.28)
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.34)
- Geology > Geological Subdiscipline (0.66)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Limestone (0.34)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Successful Multistage Hydraulic Fracturing Treatments Using a Seawater-Based Polymer-Free Fluid System Executed From a Supply Vessel; Lebada Vest Field, Black Sea Offshore Romania
Bukovac, Tomislav (Schlumberger) | Belhaouas, Rafik (Schlumberger) | Perez, Daniel Rafael (Schlumberger) | Dragomir, Alexandru (Petrom SA) | Ghita, Viorel (Petrom SA) | Webel, Carlos Emilio (Schlumberger)
Abstract Offshore operations are extremely expensive because of the operational environment and the necessary infrastructure. In this environment, emphasis is placed on high-efficiency operations based on specially tailored solutions combining available resources with new technologies. This results in a significant impact on operational efficiency by lowering costs and ultimately increasing hydrocarbon production. To introduce greater efficiencies in offshore operations, a horizontal openhole candidate well was selected to be equipped with a permanent completion system that would enable multiple fracturing treatments. Later, it was determined that by using a novel viscoelastic polymer-free surfactant-based fluid, the entire operation could be performed in a single operation, adding additional savings to the process and improving efficiency. Interpreted openhole images and advanced sonic logs were used to determine the optimum completion configuration and to select favorable fracture initiation points and treatment designs. Because a specialized fracturing vessel tailored for operations in the Black Sea was not available, a supply vessel was used. The vessel had all required fracturing equipment rigged up and secured on decks. To enable sufficient fracturing fluid volume for placing three propped fracturing treatments in a single pumping operation, a polymer-free fracturing fluid was formulated and mixed with seawater continuously. This novel multistage fracturing system was introduced in Europe for the first time. Results indicate a sustained increased production. Because of this success, additional wells are scheduled to be stimulated using same approach in the following months. Introduction The Lebada Vest field is situated ~95 km offshore Romania in the Black Sea. This field was discovered in 1984 and put on production in 1993. Since then, numerous vertical oil and gas wells were drilled and completed (Fig. 1). The wells were produced initially in natural flow and later equipped with gas lift to enhance ultimate hydrocarbon recovery. The target reservoir is a Cretaceous-age formation located at depths of ~1,900-m true vertical depth (TVD) composed of varying shale, sandstone, and carbonate content. The laminated pay zone is generally formed by streaks with permeability ranging from 0.1 md to 2.0 md and average of 0.8 md. Reservoir rock porosity ranges between 15% and 22%. Bottomhole static pressure (BHSP) at ~1,850 m true vertical depth sub sea (TVDSS) sub sea is ~220 bars and bottom hole static temperature (BHST) is 93°C.
- North America > Canada > Alberta (0.64)
- Europe > Romania > Black Sea (0.62)
- North America > United States > Texas (0.47)
- Geology > Geological Subdiscipline > Geomechanics (0.89)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.34)
- South America > Brazil > Campos Basin (0.99)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- Europe > Romania > Black Sea > Histria Basin > Istria Block > Lebada West Field (0.99)
- (2 more...)