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Results
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)
Building Trust in History Matching: The Role of Multidimensional Projection
Hajizadeh, Yasin (Department of Computer Science, University of Calgary) | Amorim, Elisa Portes (Department of Computer Science, University of Calgary) | Costa Sousa, Mario (Department of Computer Science, University of Calgary)
Abstract Assisted history matching frameworks powered by stochastic population-based sampling algorithms have been a popular choice for real-life reservoir management problems for the past decade. These methods provide an ensemble of history-matched models which can be used to quantify the uncertainty of future field performance. As a critique, population-based algorithms are generally considered black-boxes with little knowledge of their performance during history matching. In most cases, the misfit value is used as the only criteria to monitor the sampling algorithms and assess their quality. This paper applies three recently developed multidimensional projection schemes as a novel interactive, exploratory visualization tool for gaining insights to the sampling performance of population-based algorithms and comparing multiple runs in history matching. We use Least Square Projection (LSP), Projection by Clustering (ProjClus) and Principle Component Analysis (PCA) to examine the relationship between exploration of search space and the uncertainty in predictions of reservoir production. These projection techniques provide a mapping of the high dimensional search space into a 2D space by trying to maintain the distance relationships between sampled points. The application of multidimensional projection is illustrated for history matching of the benchmark PUNQ-S3 model using ant colony, differential evolution, particle swarm and the neighbourhood algorithms. We conclude that multi-dimensional projection algorithms are valuable diagnostic tools that should accompany assisted history matching workflows in order to evaluate their performance and compare ensembles of history-matched models. Using the projection tools, we show that misfit value - as an indicator of match quality - is not the only important factor in making reliable predictions. We demonstrate that exploration of the search space is also a critical element in the uncertainty quantification workflow which can be monitored with multidimensional projection schemes.
Abstract The growing demand for oil has emboldened producing companies to reenter old wells to further improve productivity and recovery. This requires monitoring the water saturation. Successes in reservoir saturation monitoring petrophysical analysis have increased the confidence to drill sidetracks in watered wells that have bypassed oil potential. Several techniques can be used to perform the analysis. The Pulsed Neutron Capture (PNC) log is one of the most popular slim cased hole formation evaluation logging tools, which allow running the surveys without having to pull out the production string. Under the right conditions, the PNC logs can be run periodically in the time-lapse mode to monitor changes in water saturation and movements in the oil-water contact and gas-oil contact. The wellbore environment may change between runs and this can complicate the analysis. For example, the borehole fluids may be different: gas, oil or brines of varying salinities. Also, changes in the downhole completion hardware can require running the logs through different tubular configurations. One has to be cognizant of all these environmental effects and appropriately correct for them to obtain the true formation properties, and to make comparisons between runs in the time-lapse analysis. Different vendors use different correction schemes. In this paper we will discuss case studies with a methodology from one Service Company that uses a weighted database approach, which relies on characterizing the tool response in known environments. The paper shows some of the advantages and disadvantages of this technique, and in particular, when the downhole conditions deviate from the characterized environment. Alternative methodologies will be proposed to get the best possible results, based on this study. Finally, examples from Saudi Arabian wells will be shown where the computed capture cross section and neutron porosity were successfully corrected in challenging borehole conditions.
- Europe (1.00)
- North America > United States (0.70)
- Asia > Middle East > Saudi Arabia (0.70)
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.
Determining Gas Flow Rate and Formation Thermal Conductivity from Pressure and Temperature Profiles in Vertical Well
Barrett, E.. (Santos Ltd) | Abbasy, I.. (Santos Ltd) | Wu, C. R. (University of Adelaide, Australia) | You, Z.. (University of Adelaide, Australia) | Bedrikovetsky, P.. (University of Adelaide, Australia)
Abstract The gas flow rate and the formation thermal conductivity distributions along the gas well have been determined from the measured pressure and temperature profiles using production logging tools, which is much cheaper and more precise than the traditional procedures of direct flow metering. An effective and robust method is proposed in this work: the system of governing equations for non-isothermal gas flow in vertical well is solved using the Runge-Kutta method; then the flow rate and formation thermal conductivity are obtained by optimising the modelled profiles of pressure and temperature based on the measured profiles. Application of the algorithm to field case shows good agreement between the directly measured and modelled pressure and temperature profiles; the flow rate prediction is consistent with flowmeter (PLT) data; the thermal conductivity profile is also in a good agreement with that obtained from lithology log. It validates the proposed method.
- Europe (0.68)
- North America > United States > Texas (0.46)
- Oceania > Australia > South Australia > Cooper Basin (0.99)
- Oceania > Australia > Queensland > Cooper Basin (0.99)
Abstract Significant reduction in well productivity of gas-condensate reservoirs occurs owing to reduced gas mobility arising from the presence of condensate/water liquid phases around the wellbore. As wettability modifiers, fluorinated chemicals are capable of delivering a good level of oil and water repellency to the rock surface, making it intermediate gas-wet and alleviating such liquid blockage. The main objective of this experimental work has been to propose an effective chemical treatment process for carbonate rocks, which have received much less attention in comparison to sandstone rocks. Screening tests, including contact angle measurements and compatibility tests with brine, were performed using mainly anionic and nonionic fluorosurfactants. On positively charged carbonate surfaces the anionic chemicals were sufficiently effective to repel the liquid phase, whilst the nonionic chemicals showed an excellent stability in brine media. A new approach of combining anionic and nonionic chemical agents is proposed, to benefit from these two positive features of an integrated chemical solution. A number of low and high permeability carbonate cores have been successfully treated using chemicals selected through screening tests. Optimization of solvent composition and filtration of the solution before injecting chemicals into the core proved very effective in reducing/eliminating the risk of possible permeability damage due to deposition of large chemical aggregates on the rock surface. The chemical solution optimized in this study can be applied as an efficient wettability modifier for mitigating the negative impact of condensate/water banking in carbonate gas-condensate reservoirs.
- North America > United States > Texas (0.69)
- North America > United States > California (0.68)
- Europe > Norway > North Sea > Central North Sea (0.28)
- Research Report > New Finding (0.48)
- Overview > Innovation (0.34)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.36)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.34)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.71)
- North America > United States > Mississippi > Pond Field (0.99)
- North America > United States > California > San Joaquin Basin > Cal Canal Field (0.99)
- Europe > Norway > Norwegian Sea > Halten Terrace > PL 479 > Block 6506/12 > Åsgard Field > Smørbukk Field > Åre Formation (0.99)
- (9 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Gas-condensate reservoirs (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 (1.00)
Abstract There may be various drivers to implement Produced Water Re-Injection (PWRI). However, re-injecting produced water from the same field cannot replace the voidage created by production, especially early in the life of the field, since most of that voidage is created by hydrocarbon extraction. Thus seawater may have to be considered to "top up" PWRI. This raises the question of what are the implications for scale control of mixing potentially incompatible brines before injection, compared to the conventional injection scenario where the mixing takes place in the reservoir. A study was set up to consider scale management during the life cycle of four offshore fields. The available data included analysis of formation and produced water and seawater compositions, and the time evolution of the produced water – seawater split in the injection system. The tools used included thermodynamic scale prediction and reservoir simulation calculations. Thus the evolution of the scale risk over the entire water cycle – from injection, through the reservoir, to production could be evaluated. The produced water compositions and the results of the calculations show that the scale risk at the producers is much lower than if only seawater had been injected. Calculations were also performed to identify whether bullhead application of scale inhibitor would provide adequate protection for the wells. This was important, as some of the wells are subsea completions. The clear conclusion was that any residual scale risk at the producer wells could be managed by bullhead squeezing. However, the corollary is that the scale risk at the injectors is much higher. The trigger for scale precipitation in this scenario is brine mixing, but instead of that happening in the reservoir, here it occurs before injection. Thus the location of greatest scale risk is moved much further upstream in the flow process.
- Europe > United Kingdom (0.46)
- North America > United States (0.46)
- Europe > Norway (0.28)
- Europe > Denmark (0.28)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (0.36)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Block 21/10 > Forties Field > Forties Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 019 > Block 7/12 > Ula Field > Ula Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > King Lear Area > Block 7/12 > Ula Field > Ula Formation (0.99)
- Europe > Denmark > North Sea > Danish Sector > Norwegian-Danish Basin > Siri Canyon > Block 5604/20 > Siri Field (0.98)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Health, Safety, Environment & Sustainability > Environment > Water use, produced water discharge and disposal (1.00)
For compositional reservoir simulation it has been reported that the phase equilibrium calculations may consume up to 70% of the CPU time of a run depending on the space and time discretization as well as on the fluid EoS model complexity, thus rendering computations acceleration as of major importance. At each grid block and for each time step, one needs to know the number and type of the coexisting equilibrium phases for a given feed composition and thermodynamic conditions and firstly a phase stability test should be conducted to be followed, whenever required, by a phase split calculation for providing the molar fraction and composition of each equilibrium phase. Evidently, the quality of the results bear direct impact on the accuracy of the simulation as they provide PVT and physical properties data input to the flow, mass and energy equations. Since the pioneering work of Michelsen on the stability and the phase-split problems (Michelsen 1982a; 1982b), a large number of studies have been presented aiming at accelerating such computations. The standard approach for speeding up computations is to lump the reservoir fluid composition into a smaller number of pseudo-components (Whitson 2000) while preserving as much as possible the EoS model accuracy. Reduction methods were initiated by Michelsen (1986) who was the first one to link the number of non-linear equations that need to be solved in phase-split calculations to the rank of the binary interaction coefficients matrix (BIC) by showing that in the extreme case of zero BIC, the system equations are only three, on the condition that the Van der Waals mixing rules are utilized. Hendricks and Van Bergen (1992), Firoozabadi and Pan (2002) and Pan and Firoozabadi (2002) extended this idea to phase stability calculations and to fluids with non-zero BIC. By applying singular value decomposition to the BIC matrix and by maintaining only its dominant directions, the n original variables are replaced by a set of m new ones with m n thus significantly reducing both problems dimensionality.
- Europe (1.00)
- North America > United States > Texas (0.93)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Artificial intelligence (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)
Smart Waterflooding (High Sal/Low Sal) in Carbonate Reservoirs
Zahid, Adeel (SPE, Center for Energy Resources Engineering, Department of Chemical and Biochemical Engineering) | Stenby, Erling H. (SPE, Center for Energy Resources Engineering, Department of Chemical and Biochemical Engineering) | Shapiro, Alexander A. (SPE, Center for Energy Resources Engineering, Department of Chemical and Biochemical Engineering)
Abstract In the last decade, high salinity waterflooding has been emerged as a prospective EOR method for chalk reservoirs. Most recently, Saudi Aramco reported significant increase in oil recovery by low salinity waterflooding in Saudi Arabian carbonate reservoirs. Understanding of the mechanisms leading to an increase in oil recovery in both smart waterflooding processes (low and high salinity waterflooding) is still not clear. In this paper, we investigate experimentally the recovery mechanisms for both methods. To understand high salinity waterflooding process, we studied crude oil/seawater ions interaction at different temperatures, pressures and sulfate ion concentrations. For low salinity waterflooding, flooding experiments were carried out initially with the seawater, and afterwards the contribution to oil recovery was evaluated by sequential injection of various diluted versions of the seawater. Our results show that sulfate ions may help decrease the crude oil viscosity when high salinity brine is contacted with oil under high temperature and pressure. We have also observed formation of an emulsion phase between high salinity brine and oil with the increase in sulfate ion concentration at high temperature and pressure. We propose that the decrease in viscosity and formation of an emulsion phase could be the possible reasons for the observed increase in oil recovery with sulfate ions at high temperature in chalk reservoirs, besides the mechanism of the rock wettability alteration, which has been reported in most previous studies. No low salinity effect was observed for the reservoir carbonate core plug at the room temperature. On the contrary, a significant increase in oil recovery was observed under low salinity flooding of the reservoir carbonate core plugs at 90 °C. NMR measurements indicated that low salinity brines did not significantly change the surface relaxation of the carbonate rocks. Migration of fines, dissolution and destruction of rock particles are possible mechanisms of oil recovery increment with low salinity brines from carbonate core plugs at 90 °C. At the present stage, the mechanisms behind increment in oil recovery under various conditions appear to be different.
- North America > United States (1.00)
- Europe (1.00)
- Asia > Middle East > Saudi Arabia (0.68)
- Geology > Mineral > Sulfate (0.97)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Limestone (0.55)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > Middle East Government > Saudi Arabia Government (0.54)