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Collaborating Authors
Reservoir Characterization
Abstract In this paper we are continuing our previous works (SPE-143142 and WHOC11-353) to investigate the best development options for a major heavy oil reservoir within the GCC region. In the early stage of this work the most applicable EOR methods were selected, and several simulation runs were conducted to find the optimal injection scenarios and rank them based on the oil recovery factor (ORF). In this paper a comparative study and a sensitivity analysis of various operational conditions and reservoir parameters were conducted in order to (1) find the optimum conditions to achieve a high RF and (2) understand the effect of reservoir heterogeneity on the reservoir performance. The investigated operational parameters are the Steam injection rate, injection swapping time and the perforation location. The investigated reservoir parameters are oil viscosity, initial water saturation, porosity and permeability. In addition to investigating these reservoir parameters, the oil price sensitivity was investigated to evaluate the financial feasibility of the selected recovery methods within a historical and forecasted oil price range. The preliminary results show that the RF is very sensitive to the oil viscosity value and the relation between them is a nonlinear relation. The Simulation results also indicate that the increase in the porosity and permeability accelerates performance; however, the opposite is not true for the initial water saturation value. From an economic perspective, production acceleration would improve overall project economics by mitigating the negative impact of discounting on the revenue stream due to the low oil price. Economically, all successive scenarios support a successful investment at the lowest (expected) oil price; in contrast, the continuous steam and hot-water flooding development options show a high economic risk after the second year, at all oil price scenarios.
- Europe (0.46)
- Asia (0.46)
- North America > Canada (0.28)
- Europe > United Kingdom > Atlantic Margin > West of Shetland > Faroe-Shetland Basin > Rona Ridge > P1368 S > Block 205/26b > Lincoln Field (0.91)
- Europe > United Kingdom > Atlantic Margin > West of Shetland > Faroe-Shetland Basin > Rona Ridge > P1368 S > Block 205/26b > Greater Warwick Area (0.91)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- (2 more...)
Abstract For monitoring hydraulic fracture (HF) in oil/gas fields the most reliable seismic method to avoid the adverse effect of strong surface noises is using downhole microseismic surveys. Nevertheless, downhole measurement is more expensive and limited by the availability of suitable boreholes in the vicinity of the hydro-fracture site.By all means seismic surveys conducted on land surface bear the largest flexibility and are more economic than downhole measurements. As a significant progress in hydro-fracture monitoring Duncan et al developed a surface monitoring system using seismic arrays centered at the hydro-fracture point. This monitoring method requires large-scale and prolonged operations; thus the cost-effectiveness is still less than ideal. In this paper we present a novel approach for land monitoring of hydro-fractures that uses only sparse seismic stations far from fracturing vehicles; and the total number of seismic stations is much less than previous approaches; so that the cost-effectiveness is significantly improved. With a small-scale seismic array on land surface we have monitored the hydro-fracture processes using a vector scanning technique for imaging hydro-fractures and determining rupture focal mechanisms. The applications of this technique to a synthetic data set based on numerical modeling and the real-world field data show that it is able to trace the tempo-spatial development of hydro-fractures even when the signal to noise ratio (S/N) is lower than 0.5. The vector scanning technique significantly shows the fracture imaging quality, and provides us a costeffective approach for monitoring flow-enhancement hydro-fracture processes.
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
Abstract Time-lapse (4D) seismic data can be integrated into history matching by comparing predicted and observed data in various domains. These include the time domain (time traces), seismic attributes, or petro-elastic properties such as acoustic impedance. Each domain requires different modelling methods and assumptions as well as data handling workflows. The aim of this work is to investigate the degree to which the choice of domain influences theoutcome of history matching on the choice of best model and associated uncertainties. Another aspect of history matching is that long simulations often pose an obstacle for an automatic approach. In this study we use appropriately upscaled models manageable in the automatic history matching loop. We apply manual and assisted seismic history matching to the Schiehallion field. In the assisted approach, the optimization loop is driven by a stochastic algorithm, while the manual workflow is based on a qualitative comparison of 4D seismic maps. By upscaling we obtained an order of magnitude gain in performance. Accurate upscaling was ensured by thorough volume and transmissibility calculation within regions. The parameterisation of the problem is based on a pattern of seismically derived geobodies with specified transmissibility multipliers between the regions. Seismic predictions are made through petro-elastic modelling, 1D convolution, coloured inversion and calculation of different attributes. We were able to achieve a reasonable match of production and 4D seismic data using coarse scale models in manual and assisted approaches. We observed that the misfit surfaces are different when working in the various seismic domains considered. Use of equivalent domains for observed and predicted data was found to give a more unique misfit response and better result. Accurate comparison of predicted and observed 4D seismic data in different domains is necessary for tackling non-uniqueness of the inverse problem and hence reducing the uncertainty of field development predictions.
- Europe > United Kingdom > Atlantic Margin > West of Shetland (0.35)
- North America > United States > Texas > Harris County > Houston (0.28)
- Geophysics > Time-Lapse Surveying > Time-Lapse Seismic Surveying (1.00)
- Geophysics > Seismic Surveying (1.00)
- North America > United States > Louisiana > East Gulf Coast Tertiary Basin > Bay Marchand Field (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Block 22/7 > Nelson Field > Forties Formation (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Block 22/6a > Nelson Field > Forties Formation (0.99)
- (17 more...)
- Reservoir Description and Dynamics > Reservoir Simulation > History matching (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Four-dimensional and four-component seismic (1.00)
Abstract The seasonal imbalance between supply and demand of renewable energy requires temporary storage, which can be achieved by hot water injection in warm aquifers. This requires that the permeability and porosity of the aquifer are not reduced significantly by heating. We present an overview of published results regarding the effect of temperature on sandstone permeability. These tests are performed with mineral oil, nitrogen gas, distilled water and solutions of NaCl, KCl, CaCl2 as well as brines that contain a mixture of salts. Thirteen sandstone formations, ranging from quartz arenites to formations with a significant fraction of fine particles including clay minerals are investigated. The porosities range from 0.10 to 0.30 and permeabilities span the range from 1 to 1000 md. To compare different rock types, specific surface is determined from permeability and porosity using Kozeny's equation. Heating causes thermal expansion, which results in porosity reduction if the sandstone is confined. The maximum effect of porosity reduction as a result of thermal expansion on permeability is modelled and compared the change in specific surface that is computed from the reported data. This does not account for all the permeability reductions observed. Permeablity reduction occurs both when distilled water is the saturating fluid as well as in tests with NaCl, KCl or CaCl2 solutions, however, this is not the case in tests with mineral oil or nitrogen gas. The formation of a filter cake or influx of colloidal particles due to corrosion of the apparatus at elevated temperature causes permeability reduction in a number of investigations. Mobilisation of internal particles, particularly kaolinite particles, is considered a probable mechanism of permeability reduction for the other experiments reviewed here. The parameters that strongly affect the success of heat storage therefore include the quality of the equipment and particularly the prevention of corrosion, as well as the sandstone lithology and its interaction with the reservoir fluid.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Mineral > Silicate (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.60)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
Adjoint-based History-Matching of Production and Time-lapse Seismic Data
Van Essen, G. M. (Shell Global Solutions International (SGSI)) | Jimenez, E. A. (Shell International E) | Przybysz-jarnut, J. P. (SGSI) | Horesh, L.. (IBM) | Douma, S. G. (Shell Technology Oman) | van den Hoek, P. J. (SGSI, A. Conn) | Conn, A.. (IBM) | Mello, U. T. (IBM)
Abstract Time-lapse (4D) seismic attributes can provide valuable information on the fluid flow within subsurface reservoirs. This spatially-rich source of information complements the poor areal information obtainable from production well data. While fusion of information from the two sources holds great promise, in practice, this task is far from trivial. Joint Inversion is complex for many reasons, including different time and spatial scales, the fact that the coupling mechanisms between the various parameters are often not well established, the localized nature of the required model updates, and the necessity to integrate multiple data. These concerns limit the applicability of many data-assimilation techniques. Adjoint-based methods are free of these drawbacks but their implementation generally requires extensive programming effort. In this study we present a workflow that exploits the adjoint functionality that modern simulators offer for production data to consistently assimilate inverted 4D seismic attributes without the need for re-programming of the adjoint code. Here we discuss a novel workflow which we applied to assimilate production data and 4D seismic data from a synthetic reservoir model, which acts as the real - yet unknown - reservoir. Synthetic production data and 4D seismic data were created from this model to study the performance of the adjoint-based method. The seamless structure of the workflow allowed rapid setup of the data assimilation process, while execution of the process was reduced significantly. The resulting reservoir model updates displayed a considerable improvement in matching the saturation distribution in the field. This work was carried out as part of a joint Shell-IBM research project.
- North America > United States (0.28)
- Europe (0.28)
- Geophysics > Time-Lapse Surveying > Time-Lapse Seismic Surveying (1.00)
- Geophysics > Seismic Surveying (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation > History matching (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Four-dimensional and four-component seismic (1.00)
Abstract This presentation outlines an integrated workflow that incorporates 4D seismic data into the Ekofisk field reservoir model history matching process. Successful application and associated benefits of the workflow benefits are also presented. A seismic monitoring programme has been established at Ekofisk with 4D seismic surveys that were acquired over the field in 1989, 1999, 2003, 2006 and 2008. Ekofisk 4D seismic data is becoming a quantitative tool for describing the spatial distribution of reservoir properties and compaction. The seismic monitoring data is used to optimize the Ekofisk waterflood by providing water movement insights and subsequently improving infill well placement. Reservoir depletion and water injection in Ekofisk lead to reservoir rock compaction and fluid substitution. These changes are revealed in space and time through 4D seismic differences. Inconsistencies between predicted 4D differences (calculated from reservoir model output) and actual 4D differences are therefore used to identify reservoir model shortcomings. This process is captured using the following workflow: (1) prepare and upscale a geologic model, (2) simulate fluid flow and associated rockphysics using a reservoir model, (3) generate a synthetic 4D seismic response from fluid and rock physics forecasts, and (4) update the reservoir model to better match actual production/injection data and/or the 4D seismic response. The above-mentioned Seismic History Matching (SHM) workflow employs rock-physics modeling to quantitatively constrain the reservoir model and develop a simulated 4D seismic response. Parameterization techniques are then used to constrain and update the reservoir model. This workflow updates geological parameters in an optimization loop through minimization of a misfit function. It is an automated closed loop system, and optimization is performed using an in-house computer-assisted history matching tool using evolutionary algorithm. In summary, the Ekofisk 4D SHM workflow is a multi-disciplinary process that requires collaboration between geological, geomechanical, geophysical and reservoir engineering disciplines to optimize well placement and reservoir management.
- North America > United States > Texas (0.68)
- Europe > Norway > North Sea > Central North Sea (0.27)
- Geology > Structural Geology (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geophysics > Time-Lapse Surveying > Time-Lapse Seismic Surveying (1.00)
- Geophysics > Seismic Surveying (1.00)
- Europe > Norway > Norwegian Sea > Halten Terrace > Block 6507/8 > Heidrun Field > Åre Formation (0.99)
- Europe > Norway > Norwegian Sea > Halten Terrace > Block 6507/8 > Heidrun Field > Tilje Formation (0.99)
- Europe > Norway > Norwegian Sea > Halten Terrace > Block 6507/8 > Heidrun Field > Ile Formation (0.99)
- (22 more...)
- Reservoir Description and Dynamics > Reservoir Simulation > History matching (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Four-dimensional and four-component seismic (1.00)
- Information Technology > Modeling & Simulation (1.00)
- Information Technology > Artificial Intelligence > Representation & Reasoning (1.00)
- Information Technology > Artificial Intelligence > Machine Learning > Evolutionary Systems (0.88)
- Information Technology > Artificial Intelligence > Machine Learning > Statistical Learning (0.68)
Abstract Several offshore gas fields are present in Adriatic Sea (Italy), producing since the 60s from multilayer metric sand reservoirs. The declining production in these mature fields is normally offset by drilling new deviated wells. Recent technology evolution shifted the focus from metric reservoirs to thinly laminated intervals (thin beds), until now not produced due to difficulties in identifying gas bearing zones. While gas identification in metric reservoirs can be normally achieved with standard petrophysical measurements, thin beds are challenging since lamination thickness is half inch or less and even advanced petrophysical logs struggle in discriminating gas from water in this environment. Conventional pressure gradient approach also does not work, since thin beds are often overpressurized and pressures are supercharged due to low mobility. A new wireline formation testing approach for thin beds to discriminate gas from water zones was introduced, using a dual packer string with downhole fluid analysis capabilities, including fluid density measurement. This provided the possibility of testing very low permeability zones with high uncertainties in saturations. Dual packer tests were also successfully carried out in the underlying shale formation never considered before a real reservoir, revealing potential for gas production. The possibility to verify gas presence in zones with high uncertainties saved the cost of multiple well tests, optimized the completion strategy of the different reservoirs and allowed to increase the field production and reserves, reducing at the same time uncertainties in reservoir model. Four jobs with dual packer and downhole fluid analysis to test thin beds were performed so far in Barbara NW, Barbara and Clara Fields, resulting in added gas reserves estimated in 2 Billions Sm3 and gas production higher than the one at fields startup several years ago. This is a remarkable result for development wells in a mature environment (balanced exploration), maximizing asset value. Based on these results, several gas fields producing today from metric reservoirs will be revisited in the very near future in order to start production from thin beds, untouched until now, with the advanced wireline formation testing approach described in this paper playing a key role.
- Europe > Italy (0.52)
- North America > United States > Texas > Wichita County (0.24)
- North America > United States > Texas > Archer County (0.16)
- Europe > United Kingdom > North Sea > Central North Sea (0.16)
- North America > United States > Texas > Fort Worth Basin > Barbara Field (0.99)
- North America > United States > Texas > Fort Worth Basin > Clara Field (0.98)
- Well Completion > Well Integrity > Zonal isolation (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- (3 more...)
Multidisciplinary Approach for Novel Application of Formation-pressure-while-drilling Service in High Temperature (160 Deg.C) Low Permeability Carbonate
Bruni, Corrado (BG Group) | Odumboni, Idowu (BG Group) | Sellami, Besma (BG Group) | Turner, Marcus (Schlumberger) | Sanguinetti, Marco (Schlumberger) | Kazmer, Jorge (Schlumberger)
Abstract The Abiod formation is the principal target in the Miskar field, offshore Tunisia. Consisting of fractured geomechanically stressed carbonate with a measured matrix permeability as low as 0.1 mD. The formation dates from Campanian to lower Maastrichtian and forms a horst structure. The formation has been under production since 1996. Obtaining formation pressure data was considered critical for determining the magnitude of depletion from production, well-to-well comparisons for vertical and lateral connectivity, forward modeling, completion decisions, and refinement of the field development plan. Historically, this has been a challenge with conventional wireline (WL) formation testers for the following reasons: Severe depletion and well deviation causing differential sticking High temperatures (150 to 195° C) at the limit of tool electronics Low permeability Fractures and breakouts that can impact seal success This was overcome with a systematic multidisciplinary approach. After review of historical formation testing data, and influence on seal success with probe vs. packer elements, it was decided to apply formation-pressure-while-drilling (FPWD) technology. The key questions with FPWD in this environment are: Can we achieve a good transient profile and what is potential impact of supercharging? These questions were addressed with advanced prejob modeling, which enabled determination of an optimized pretest configuration and testing procedure to minimize potential supercharging effects. While drilling, stage-in procedures were used, and mud logging total gas data were gathered to identify areas of liberated gas. Pre-run wireline petrophysical data were gathered to characterize the Petrophysical properties of the reservoir and to calculate an intrinsic permeability profile. Ultrasonic borehole images and caliper data were used to determine the principal horizontal stress directions, fracture frequency, and orientation and to confirm the stratigraphic dipping of the structure. Combined, this information allowed a focused orientation of the FPWD probe and optimal station selection avoiding fractures and breakouts. This novel approach resulted in 100% seal success, >50% improvement. Four days of rig time were saved, and the required data were obtained.
- Europe (0.66)
- Africa > Middle East > Tunisia > Mediterranean Sea (0.25)
- Geology > Geological Subdiscipline > Stratigraphy (0.48)
- Geology > Geological Subdiscipline > Geomechanics (0.35)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (0.67)
- Africa > Middle East > Tunisia > Mediterranean Sea > Gabes Basin > Miskar Field (0.99)
- Africa > Middle East > Tunisia > Kairouan Governorate > Pelagian Basin > Sidi El Kilani Concession (SLK) Permit > Abiod Formation (0.99)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
Abstract Karachaganak field is one of the largest accumulations of gas-condensate in the world in production since 1985. Located in the northern Pricaspian Basin (Kazakhstan) the field is a Permo-Carboniferous isolated carbonate platform with a hydrocarbon column that resides within different environments of deposition. The distribution of reservoir properties has been largely debated because of both the depositional heterogeneity and the diagenetic overprint. These uncertainties were assessed by analyzing and integrating the vast amount of geological and production data to build a predictive history matched reservoir model. Seismic facies analysis, with support from outcrop analogues and integrated with field core and log data, reveals, within stratigraphic intervals, "Depositional Regions" (DRs) that ranges from platform interior bedded deposits to aggrading/prograding mounds, clinoforms, slopes and basin sediments. These DRs were first seismically mapped, identifying field scale heterogeneity, and then petrophysically characterized using geologic and dynamic data. A sequence of progressively optimized models was built according to geologically meaningful concepts that make use of DRs and critical petrophysical issues (such as enhanced/matrix permeability, sealing barriers and dolomitization) were in parallel addressed. A reference model has been so defined and a history match of remarkable quality has been achieved for this complex heterogeneous reservoir. The uncertainty was investigated in a pragmatic manner using HM as benchmark. The reservoir uncertainty decreases closer and closer to the wells, hence alternative models scenarios were built by gradually changing DRs petrophysical properties going away from the production wells. Using the distance and the magnitude of the perturbations as control parameters and the quality of history match as selection criterion, we could identify two "end members??. These cases represent possible alternative scenarios both consistent with the geological data and still endorsed by a high quality history match, two reservoir models capable to give a significant spread in the production forecast.
- Phanerozoic > Paleozoic > Devonian (1.00)
- Phanerozoic > Paleozoic > Carboniferous > Mississippian > Middle Mississippian > Visean (0.68)
- Phanerozoic > Paleozoic > Permian > Cisuralian > Asselian (0.48)
- Geology > Sedimentary Geology > Depositional Environment (1.00)
- Geology > Geological Subdiscipline > Stratigraphy (1.00)
- Geology > Structural Geology > Tectonics (0.93)
- (2 more...)
- Asia > Kazakhstan > West Kazakhstan > Uralsk Region > Precaspian Basin > Karachaganak Field (0.99)
- Asia > Kazakhstan > West Kazakhstan > Precaspian Basin (0.99)
- Asia > Kazakhstan > Mangystau Oblast > Precaspian Basin > Tengiz Field > Tengiz Formation (0.99)
- (32 more...)
- Reservoir Description and Dynamics > Reservoir Simulation > History matching (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- (3 more...)
Abstract Over the last decade the ensemble Kalman filter (EnKF) has attracted attention as a promising method for solving the reservoir history matching problem: Updating model parameters so that the model output matches the measured production data. The method possesses unique qualities such as; it provides real time update and uncertainty quantification of the estimate, it can estimate any physical property at hand, and it is easy to implement. The method does, however, have its limitations; in particular it is derived based on an assumption of a Gaussian distribution of variables and measurement errors. A recent method proposed to improve upon the original EnKF method is the Adaptive Gaussian mixture filter (AGM). The AGM loosens up the requirements of a linear and Gaussian model by making a smaller linear update than the EnKF and by including importance weights associated with each ensemble member at computational costs as low as EnKF. In this paper we present a refined AGM algorithm where the importance weights are included in the calculation of the apriori and the aposteriori covariance matrices. Moreover, in this paper the AGM algorithm is for the first time applied to a real field study. To validate the performance of AGM the results are compared with the EnKF, with and without distance based localization. Several statistical measures are used to validate the performance of the filters, and we are able to distinguish the performance of the different filters. In particular all the methods provide good history match, but we see that the AGM stands out by better honoring the original geostatistics and by providing consistent predictions when rerun is performed.
- North America > United States (0.46)
- Europe (0.46)
- Africa (0.28)
- Reservoir Description and Dynamics > Reservoir Simulation > History matching (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation > Evaluation of uncertainties (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Geologic modeling (1.00)
- Data Science & Engineering Analytics > Information Management and Systems (1.00)