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Engineers need to predict the production characteristics from hydraulically fractured wells in tight gas fields. Decline curve analysis (DCA) has been widely used over many years in conventional oil and gas fields. It is often applied to tight gas, but there is uncertainty regarding the period of production data needed for accurate prediction.
In this paper decline curve analysis of simulated production data from models of hydraulically fractured wells is used to to develop improved methods for calibrating decline curve parameters from production data. The well models were constructed using data from the Khazzan field in Oman. The impact of layering, permeability and drainage area on well performance is also investigated. The contribution of each layer to recovery and the mechanisms controlling that contribution is explored.
The investigation shows that increasing the amount of production data used to fit a hyperbolic decline curve does not improve predictions of recovery unless that data comes from many years (20 years for a 1mD reservoir) of production. This is because there is a long period of transient flow in tight gas reservoirs that biases the fitting and results in incorrect predictions of late time performance. Better predictions can be made by estimating the time at which boundary dominated flow is first observed (tb), omitting the preceding transient data and fitting the decline curve to a shorter interval of data starting at tb. For single layer cases, tb can be estimated analytically using the permeability, porosity, compressibility and length scale of the drainage volume associated with the well. Alternatively, tb can be determined from the production data allowing improved prediction of performance from 2-layer reservoirs provided that a) there is high cross-flow or b) there is no cross-flow and the lower permeability layer either does not experience BDF during the field life time or it is established quickly.
Two new Non-Intrusive Reduced Order Modelling approaches to estimate time varying, spatial distributions of variables from arbitrary unseen inputs are introduced. One is a generalization of an existing'dynamic' approach which requires multiple surrogate evaluations to model the solutions at different time instances, the other is a'steady-state' approach that evaluates all time instances simultaneously, reducing the local approximation error. The ability of these approaches to estimate the water saturation distributions expected during a gas flood through a 2D, dipping reservoir is investigating for a range of unseen input parameters. The range of these parameters has been chosen so that a range of flow regimes will occur, from a gravity tongue to a viscous dominated Buckley-Leverett displacement. A number of practically relevant model error measures were employed as opposed to the standard L2 (Euclidean) norm. The influence of the number and the structure of training simulations for the model was also investigated, by employing two simple experimental design methods. The results show that POD based NIROM approaches are prone to significant deviations from the true model. The main sources of error are due to the non-smooth variation of system responses in hyperspace and the transient nature of the flows as well as the underlying dimensionality reduction. Since the first two sources are properties of the physical system modelled it may be expected that similar problems are likely to arise independently of the interpolation method and the reduction process used.
Hiller, Thomas (Leibniz Institute for Applied Geophysics) | Ardevol-Murison, Julie (Clariant Produkte GmbH) | Muggeridge, Ann (Imperial College London) | Schröter, Matthias (Max Planck Institute for Dynamics and Self-Organization) | Brinkmann, Martin (Saarland University)
We investigate the effect of the length scale of wetting heterogeneities, close to the length scale of a pore, on capillary pressure saturation (CPS) curves and the United States Bureau of Mines (USBM) and Amott-Harvey (AH) wettability indices. These macroscopic wettability indices are used to describe bulk rock wettability, because the local contact angle (the standard physical measure of wettability) in a sample is difficult to access and might vary within and between pores caused by changes in mineralogy and the surface coverage of organic materials. Our study combines laboratory experiments and full-scale fluid-dynamics simulations using the multiphase stochastic-rotation dynamics (SRDmc) model. Four model systems were created using monodisperse glass beads. The surface properties of the beads were modified so that one-half of the surface area in each system was strongly hydrophilic and the other half was hydrophobic. However, each system had a different length scale of wetting heterogeneity, ranging from a fraction of a bead diameter to two bead diameters. There is excellent agreement between the experimental and simulation results. All systems are classified as intermediate-wet on the basis of their AH and USBM indices. An examination of the capillary pressure curves shows that the opening of the stable hysteresis loop decreases monotonically as the length scale of the wetting heterogeneities is increased. Thus, our results suggest that macroscopic wettability indices could be used as indicators of ultimate recovery, but they are not suited to discriminate between the different flows that occur earlier in a mixed-wettability displacement process.
Polymer flooding and low salinity waterflooding are two different but potentially complementary Enhanced Oil Recovery (EOR) techniques. Polymer flooding improves fractional flow and sweep efficiency by improving the mobility ratio for the displacement. Low salinity waterflooding improves pore scale displacement efficiency by changing the wettability of the reservoir rocks toward more water-wet. Reduced salinity water is often used in polymer injection to reduce hydrolysis however the water salinity in this case is typically higher than that needed to obtain a true low salinity effect. This paper describes the outcomes of a systematic study into the potential benefits of combined polymer-low salinity waterflooding versus polymer-high salinity waterflooding, polymer-reduced salinity waterflooding and conventional waterflooding.
Numerical simulation, validated against analytical solutions, was used to evaluate the relative performance of these processes. The impacts of layering and reservoir heterogeneity were investigated using two-dimensional (2D) and three-dimensional (3D) reservoir models. Sensitivity studies of injected water salinity and the start time of injection were carried out in each of these models. Outcomes were compared against the recoveries and water cuts predicted using a one-dimensional (1D) analytic solution for the EOR processes to evaluate the impact of sweep versus displacement efficiency on incremental oil recovery and water cut.
Combined polymer-low salinity waterflooding shows an improvement in recovery and reduction in water cut compared with the other EOR processes in all cases. We show this is partly due to improving the fractional flow (increasing shock front saturation) but is also due to both the leading and trailing shock fronts in polymer-low salinity waterflooding being more stable than in the other EOR processes, reducing the possibility of viscous finger growth and thus increasing performance. The highest incremental oil recovery is observed when the injected water salinity in the combined polymer-low salinity waterflooding is reduced to below the low salinity threshold. It is clearly beneficial to reduce the water salinity to this low level rather than just to a salinity where hydrolysis is prevented. The injection of the combined EOR technique in tertiary mode, particularly at 75% water cut after performing high salinity waterflooding, exhibits an incremental oil recovery of between 15 and 42% and a reduction in water cut of between 11 and 48% at 1.0 pore volume injected (PVI).
This is the first systematic investigation into the performance of combined polymer-low salinity waterflooding compared with conventional waterflooding, low salinity waterflooding, and polymer flooding with reduced salinity water. It provides a clear insight into the benefits of combined EOR process justifying the need for field scale pilots and further laboratory studies.
In this paper we investigate the contribution of capillary and viscous cross-flow to oil recovery during secondary polymer flooding. Cross-flow can be an important mechanism in oil displacement processes in vertically communicating stratified reservoirs. Using polymers will change the balance of these contributions. Previous numerical investigations have shown that the amount of viscous cross-flow is controlled by the layer permeability contrast and a dimensionless number that characterises the combined effects of water, polymer and oil viscosities. The highest viscous cross-flow values were observed during favourable mobility ratio floods in reservoirs with a layer permeability ratio close to 3.
The purpose of the laboratory study was to validate previous numerical studies of cross-flow performed using commercial reservoir simulators. A series of experiments were performed in glass beadpack using analogue fluids comprising water, glycerol solution (to represent the polymer) and paraffin oil. All porous medium and fluid properties (including relative permeabilities and capillary pressure curves) needed for the numerical simulations were determined independently of the displacement experiments. Two beadpacks were constructed of two layers of different permeabilities parallel to the principal flow direction. In one of the packs a barrier was placed between the two layers to prevent cross-flow. Comparing the recoveries from these enabled us to quantify the contribution of cross-flow to oil recovery. The mobility ratios examined in the experiments ranged from very unfavourable to very favourable. The layer permeability ratio was approximately 2.5.
Good agreement was obtained between experiments and simulations, without the need for history matching, demonstrating that the simulation correctly captures the physics of crossflow. The incremental oil recoveries attributable to cross-flow and mobility control both fell within the error margins of the experimentally calculated values. The experiments showed that capillary cross-flow dominated over viscous cross-flow on laboratory length scales. Having validated the simulator, we then used it to show that wettability (with and without capillary pressure) can modify the impact of cross-flow on oil recovery.
Polymer flooding is a proven EOR/IOR process for viscous and light oil reservoirs alike. However, it results in the formation of two shocks front that require simulation models with fine grid blocks to represent field scale fluid movement. Therefore, upscaling is required to transfer such fluid behavior to coarser models. However, most upscaling methods are designed for waterflood only, while upscaling techniques for polymer flood are rarely discussed in the literature.
In this paper, A new upscaling methodology specifically designed for polymer flooding is presented to address such impracticality. The methodology allows the average flow behavior to be captured, including the effects of small scale heterogeneity whilst compensating for the impact of increased numerical diffusion present in coarse grid models.
The method is based on the pore volume weighted method for relative permeability pseudoization first derived by
Injection of carbon dioxide into deep saline aquifers is one way to reduce greenhouse gas emissions. Carbon dioxide, usually a super critical fluid at aquifer pressure and temperature conditions, is lighter than the resident brine and so forms a gas cap above the water. However, over time it dissolves in the water, creating a density inversion which induces gravitational instability. Understanding whether the dominant mixing mechanism is convective mixing rather than pure diffusion is important as this controls the timescale over which the carbon dioxide-saturated brine mixes with the unsaturated brine. This paper presents numerical simulations, using a finite difference reservoir simulator, to evaluate the predictions of analytical solutions for stability analysis and growth rate of the fingers of different wavenumbers at different Rayleigh numbers (Ra). The effects of density difference, permeability anisotropy and diffusion (both longitudinal and transverse) on fingering behaviour were investigated through the dimensionless Rayleigh number. The density difference and the vertical permeability were found to mainly control the degree of instability. At Rayleigh numbers greater than 800, fingers are present and the degree of fingering increases with Rayleigh number. Growth rate analysis showed that growth rate is directly proportional to Rayleigh number and time. The critical time (at which flow becomes unstable) varies inversely with the Rayleigh number whilst the corresponding critical wavenumber number varies linearly with the Rayleigh number. These results are consistent with previously reported linear stability analyses providing a validation of the simulator. Numerical simulation results were also validated against experiments. These validations both show that the simulator is robust and can thus be used to investigate more complex situations (heterogeneity) that cannot be analysed mathematically.
Jackson, Matthew (Imperial College) | Percival, James (Imperial College) | Mostaghimi, Peyman (Imperial College) | Tollit, Brendan (Imperial College) | Pavlidis, Dimitrios. (Imperial College) | Pain, Christopher (Imperial College) | Gomes, Jefferson (Imperial College) | Elsheikh, Ahmed H. (Imperial College) | Salinas, Pablo (Imperial College) | Muggeridge, Ann (Imperial College) | Blunt, Martin (Imperial College)
The impact of geological heterogeneity on the oil recovery and water cut obtained from secondary and tertiary low salinity water injection is investigated as a function of the size of the low salinity slug. We have used synthetic geological models including both simple layering and more geologically realistic 2D models based on the Brent formation taken from the SPE10 Model 2. Heterogeneity was quantified using a dimensionless number based on vorticity. Two different commercial simulators were used, one which models low salinity flooding using a salinity threshold limit to modify the rock's relative permeability curves with the salinity of the injected brine. The second simulator models explicitly the ion exchange between the clay surface and the injected brine's divalent ions. Results from both simulators are compared with the outcome of conventional waterflooding.
Oil recovery correlates linearly with the vorticity based heterogeneity index (where high values correspond to a more homogeneous reservoir) i.e. the additional oil recovered by low salinity water injection decreases as heterogeneity increases. A low salinity slug size of at least 0.6 PVI is beneficial in heterogeneous reservoirs increasing to 0.8 PVI in highly heterogeneous reservoirs. Significant additional oil is recovered by injecting more than 1 PV.
To date there are limited publications evaluating the impact of geological heterogeneity on the outcome of low salinity. Previous work by
An improved heterogeneity/homogeneity index is introduced that uses the shear-strain rate of the single-phase-velocity field to characterize heterogeneity and rank geological realizations in terms of their impact on secondary-recovery performance. The index is compared with the Dykstra-Parsons coefficient (Dykstra and Parsons 1950) and the dynamic Lorenz coefficient (Shook and Mitchell 2009). The results show that the index's ranking ability is preserved for miscible and immiscible displacements at different viscosity/mobility ratios. Neither the Dykstra-Parsons coefficient (Dykstra and Parsons 1950) nor the dynamic Lorenz coefficient (Shook and Mitchell 2009) can consistently discriminate between different realizations in terms of breakthrough time and oil recovery at 1 pore volume injected (PVI) for tracer flow or adverse viscosity-ratio miscible and immiscible floods.