Hu, Yu (Department of Petroleum Geology & Geology, School of Geosciences, University of Aberdeen) | Gan, Quan (Laboratory of Coal Resources and Safe Mining, China University of Mining and Technology) | Hurst, Andrew (Department of Petroleum Geology & Geology, School of Geosciences, University of Aberdeen) | Elsworth, Derek (Laboratory of Coal Resources and Safe Mining, China University of Mining and Technology)
Sand injectite complexes comprise kilometer-scale clastic intrusion networks that act as effective conduits for the migration, accumulation and then recovery of hydrocarbons and other fluids. An equivalent continuum model is constructed to represent a sand injectite reservoir, coupling stress and fluid flow in fractured rock using the continuum simulator TOUGHREACT coupled with FLAC3D to follow deformation and fluid flow. A permeability model, which uses staged percolation models, is proposed to improve permeability estimation of fracture networks by accommodating four different levels of fracture connectivity. This permeability model is confirmed against field and laboratory data, corresponding to the different connectivities of fracture networks. The new constitutive permeability model is incorporated into the coupled hydro-mechanical simulator framework and applied to sand injectites with the analysis of permeability evolution mechanisms and mechanical sensitivity. The results indicate that when the magnitudes of principal stresses increase in a constant ratio, normal closure is the dominant mechanism in reducing fracture aperture and thereby permeability. Conversely, the evolution of stress difference can accentuate aperture and permeability due to an increase in shear dilation for critically or near-critically oriented fractures. Also, the evolution of aperture and related permeability of fractured rock are more sensitive at lower stress states than at higher stress states due to the hyperbolic relationship between normal stress and normal closure of the fractures.
Reservoir models are commonly used in the oil and gas industry to predict reservoir behaviour and forecast production in order to make important financial decision such as reserves estimations, infill well drilling, enhanced oil recovery schemes, etc. Conditioning reservoir models to dynamic production data is known as history matching, which is usually carried out in an attempt to enhance the predicted reservoir performance. Uncertainty quantification is also an important aspect of this task, and encompasses identifying multiple history matched models, which are constrained to a geological concept. History matching and uncertainty quantification can be accomplished by identifying and using efficient and speedy optimisation techniques. The assisted history matching practice usually includes two practices; the first of which is parameterisation, which consists of reducing the number of matching parameters in order to avoid adjusting too many variables with respect to the amount of production data available. A challenging situation results from over-parameterisation, in addition to an ill-posed formulation of the inverse problem. The second process involves optimisation, which aims at solving the inverse problem by reducing a misfit or objective function that defines the difference between simulated and production data. The main challenges of optimisation are local minima solutions and premature convergence. The success of optimisation is greatly dependent on the parameterisation strategy used. These algorithms that analyse various parameterisation methods, combined and examined with diverse optimisation algorithms lead us to suggest novel hybrid approaches addressing the two processes of assisted history matching. We propose a multistage combined parameterisation and optimisation history matching technique. Hybridisation of parameterisation and optimisation algorithms when designed in an optimum manner can combine advantageous features of each method. This consisted of combining random initial parameter population by means of a wide parameter search space optimiser at early stages with initial models chosen from the best history matched models of previous stages based on the initial parameter distribution with a fine tuning optimisation algorithm at later stages. The re-parameterisation at the beginning of each stage of a hybrid algorithm assists the process in escaping local minima and prevents premature convergence. The general design of these algorithms is to initialise with simple parameterisation methods and wide spread search algorithms, in which parameterisation zoning is increased and the parameter search space is reduce with time. These hybrid algorithms allow for consistent and effective parameter search space definition in which more than one minimum can be reached, further reduce the misfit after an initial convergence has been reached, improve efficiency by accelerating the optimisation process saving valuable computing time and consequently, improved results are achieved. We also show that these hybrid algorithms can be the basis of an uncertainty range with improved predictability models when benchmarked with the Brugge synthetic model. In the case of a three stage hybrid algorithm, the misfit reduction in some cases can be improved by up to 50% relative to the first guess model, while the efficiency improvement of a hybrid algorithm with a stopping criterion saves up to eight hours for small models such as the Brugge model and an estimated 100 hours for larger models with up to 50,000 active gridcells. Finally, a recommended hybrid algorithm design for similar cases is established. We also prove that the results are independent of the first guess models used for history matching when analysed with the Brugge benchmark model. The hybrid methods offer a novel technique that incorporates effective parameterisation which defines an optimal parameter search space, and at the same time does not compromise the effectiveness of the misfit minimisation which leads to better predictive capabilities.
Modern, capital intensive upstream projects require integrated dynamic modeling to best project production and economics. Surface-subsurface coupling, or simply coupling, is utilized to model integrated production systems, i.e. model the reservoir, wellbore and surface facilities as one system. Three general methods of coupling exist: explicit, partially implicit and fully implicit. The explicit method requires the least computational effort, however solutions are inaccurate and often unstable. Fully implicit coupling yields the most accurate and stable solutions, however, fully implicit systems are computationally expensive and are often impractical in operational settings due to high development costs. The partially implicit method offers the best compromise between accuracy and stability. Yet, partially implicit methods still encounter instability. The general objective of this work was to create an easily implementable partially implicit scheme that was accurate and stable. The authors hypothesized that adaptive time stepping could provide a stable solution as well as reduce computational requirements. In this work, a PID control loop is utilized to perform adaptive time stepping in coupled simulation. The objective of the PID control loop was to control coupling error via the manipulation of the time step size.
A PID controller was adapted from prior literature which aimed to provide a stable and accurate solution method to numerically integrate ordinary differential equations. This controller was utilized in a commercial software package, and it overrode the commercial software's own time step selection algorithm. The commercial coupling software was utilized to act as a framework and baseline to compare with the novel PID time stepping algorithm. The only requirement of any proposed controller-software system is that the time step must be programmable at every iteration in the underlying coupling software. Simple algorithms may be used to transfer the updated time step from the controller to the coupled simulation, and ensure automatic communication between both systems. The coupled system included a 100mD, 10X10X12 grid block reservoir. Each grid block was 250X250X10 ft. The controller gains were varied to optimize the controller for the given simulation.
Results showed that the novel coupling algorithm significantly reduced computational effort, while maintaining solution accuracy and stability. In one scenario, the PID controlled simulation was 297% faster than the commercial simulation, while incurring less than 0.5% error in cumulative production. Results showed that controller gain values were critical to producing fast and stable coupled solutions. An adaptive gain schedule yielded the fastest and most accurate solution, providing motivation to develop an algorithm to select controller gains at each time step.
This work represents the first time that PID control has been used to perform adaptive time stepping in coupled simulation. This work shows that a novel time stepping scheme can be successfully incorporated to existing coupling software.
Tidal effects in wells have been observed for millennia and have been analysed since the 1970s, following the introduction of high-resolution pressure gauges. Tidal effects are usually more obvious offshore and many papers focus on offshore wells with large tidal signals. This paper demonstrates that pressure changes caused by ocean tides are detectable in near-coast land wells and that, with careful analysis and processing, provide valuable additional information for reservoir characterisation.
This paper uses a set of observations from multiple near-coast land wells with extended pressure histories acquired as part of campaign of production and interference testing for reservoir characterisation purposes. These pressure records have variable tidal signal and data quality. A variety of methods have been published to smooth tidally influenced pressure data and extract or remove the tidal component. These different tidal filtering techniques are tested on real data, and a preferred data processing procedure is selected appropriate for the large quantity and variable quality of data in the study area. The methodology allows data from multiple wells to be quickly processed and consistently screened.
This paper gives examples of tidal behaviour in selected wells and compares the results across multiple wells in the study area to show how identification of subtle tidal effects is useful for:
Field appraisal of a saturated oil-rim with gas cap by examining differences in tidal amplitude in wells in different parts of the field. Estimation of critical gas saturation by comparing tidal amplitudes before and after an extended well test. Monitoring well integrity in a producing field by tidal analysis of annular pressures.
Field appraisal of a saturated oil-rim with gas cap by examining differences in tidal amplitude in wells in different parts of the field.
Estimation of critical gas saturation by comparing tidal amplitudes before and after an extended well test.
Monitoring well integrity in a producing field by tidal analysis of annular pressures.
The paper also recommends a reservoir surveillance programme to obtain useful tidal data in onshore wells.
This paper will be useful to engineers attempting to find and interpret subtle tidal data, instead of simply removing it. It recommends a systematic approach for using tidal data in wells where tidal signals are small and/or gauge resolution is poor, based on experience with real data with variable data quality. It also provides a case study to show the value and practical application of a surveillance programme to identify tidal data in near-coast land wells.
The Sea Lion Field is an Early Cretaceous turbidite fan complex, located in the North Falkland Basin, 220 km north of the Falkland Islands. The reservoirs are dominated by amalgamated high density turbidites (Bouma Ta and liquefied sediment gravity flows), but also contain low density turbidites, linked debrites and interdigitated lacustrine mudstones. An integrated dynamic modelling workflow which incorporates the latest understanding of the Sea Lion Field sedimentology and reservoir heterogeneities is presented.
The workflow focuses on capturing and retaining reservoir heterogeneity throughout the reservoir modelling process. Coarse-scale heterogeneity is captured during the construction of the full-field geological (static) model and conserved in the dynamic model by using the same grid dimensions. Sedimentological features (fine-scale heterogeneity) below the grid resolution are captured in separate, 3D core-scale models. Through a process of
Detailed interpretation of the available core data enables a statistical evaluation, which underpins the construction of core-scale models for the individual rock types. The resulting 3D core-scale models are representative of the reservoir and the development concept in terms of reservoir dip, lithology, petrophysical and fluid properties and well spacing. Matching the coarse model behaviour to the core-scale model forecast is an inverse problem with multiple possible solutions; therefore, assisted history matching is a valuable tool for quickly obtaining, comparing and ranking possible upscaled relative permeability functions and
This integrated dynamic modelling workflow allows for the direct use of detailed geological models characterising the main heterogeneities impacting flow behaviour, while retaining the ability to investigate and capture small-scale heterogeneities below the resolution of the full-field static model, thus avoiding the cumbersome process of upscaling geological properties. Assisted history matching and optimization have been integrated into the workflow, providing a robust method to produce upscaled relative permeability functions that replicate the expected waterflood behaviour.
Sun, Junchang (Research Institute of Petroleum Exploration & Development, PetroChina) | Zheng, Dewen (Research Institute of Petroleum Exploration & Development, PetroChina) | Wang, Jieming (Research Institute of Petroleum Exploration & Development, PetroChina) | Liu, Jiandong (Research Institute of Petroleum Exploration & Development, PetroChina) | Shi, Lei (Research Institute of Petroleum Exploration & Development, PetroChina) | Xu, Hongcheng (Research Institute of Petroleum Exploration & Development, PetroChina) | Li, Chun (Research Institute of Petroleum Exploration & Development, PetroChina) | Zhong, Rong (Research Institute of Petroleum Exploration & Development, PetroChina) | Zhao, Kunshan (Research Institute of Exploration and Development of PetroChina Dagang Oilfield Company)
An effective caprock is crucial for safe operation of an underground gas storage (UGS). However, the caprock's initial seal capacity can be changed due to many factors such as micro-deformation of the caprock's pore structure and fatigue damage under cyclic loading caused by UGS annual storage which may all lead to gas leakage. Consequently, the caprock's dynamic sealing capacity including capillary sealing effciency and mechanical integrity under alternating stress must be comprehensively evaluated.
A total of 21 clayey caprock plugs drilled from the HB large UGS in western China were prepared to perform laboratory tests. Nitrogen breakthrough (BT) pressure was both measured before and after 50 cycles’ loading-unloading on the fully kerosene-saturated plugs. Specially, the cyclic amplitude was designed based on the UGS planned operational pressure bounds and local dynamic in-situ stresses. Triaxial compression fatigue and subsequent failure tests were conducted to investigate the strain dynamic evolution and its effect on the mechanical behaviors of clayey caprocks. Seventeen sandstone reservoir plugs were also selected to carry out mechanical tests as a comparison.
Experimental results indicate that the BT pressure of the HB caprock ranges from 3.88 to 8.79MPa which is much higher than the critical value (~2MPa) for the HB trap seal. Average reduction of the BT pressure is 14.8% after 50 cycles’ loading demonstrating that the alternating in-situ stresses may have a relatively minor effect on the capillary sealing capacity of the HB UGS caprock. This finding is also supported by the mechanical tests that the maximum cyclic loading is always below the yield point of the HB caprock. Compaction is the main deformation behavior and shear expansion has not occurred within the disturbed in-situ stresses variation during the HB UGS operations according to the dynamic evolution of the axial and lateral strain. However, the stress-strain curves exhibit significant hysteresis especially within the first several cycles and the plastic strain continuously develops. The average cumulative plastic strain is around 0.14% after 50 cycles’ loading which is much lower than the 1% benchmark of caprock failure suggested by Schlumberger. However, the cyclic loading has a more severe weakening effect on the caprock mechanical strength parameters and it cannot be neglected in geomechanical simulation compared with the sandstone reservoir plugs.
This study gives an in-depth understanding of the dynamic capillary sealing capacity and mechanical properties of the clayer caprocks under cyclic loading-unloading. Based on the above experimental finds, the more accurate evaluation will be obtained through 3D geomechanical model simulation.
Ranaee, Ehsan (Dipartimento di Energia Politecnico di Milano, Via Lambruschini 4, 20156 Milano) | Inzoli, Fabio (Dipartimento di Energia Politecnico di Milano, Via Lambruschini 4, 20156 Milano) | Riva, Monica (Dipartimento di Ingegneria Civile e Ambientale, Politecnico di Milano, Piazza L. Da Vinci 32, 20133 Milano) | Cominelli, Alberto (Eni - S.p.A. Via Emilia 1, 20097 San Donato Milanese, Milano) | Guadagnini, Alberto (Dipartimento di Ingegneria Civile e Ambientale, Politecnico di Milano, Piazza L. Da Vinci 32, 20133 Milano)
We study the way uncertainty associated with estimates of parameters of three-phase relative permeability models, including hysteresis, propagates to responses of reservoir simulations under Water Alternating Gas (WAG) conditions. We model three-phase relative permeabilities by: (i) joint calibration (on threephase data) of a recent oil relative permeability model (Ranaee et al., 2015) and of the Larsen and Skauge (1998) gas relative permeability hysteretic model; and (ii) the common practice of relying on three-phase oil relative permeability models that are characterized solely on the basis of two-phase information (e.g., Stone, 1970 and Baker, 1988) in conjunction with the formulation of Larsen and Skauge (1998) for threephase gas relative permeability. While model parameters associated with the former approach are linked to an estimation uncertainty, those of the models relying only on two-phase data are not. A numerical Monte Carlo (MC) framework is employed to estimate propagation to reservoir simulation outputs of uncertainty of parameters estimated through model calibration on three-phase data. Our findings suggest that evaluation of oil relative permeability through a saturation-weighted interpolation Baker model, even in combination with a three-phase gas relative permeability hysteresis model, yields the lowest values of field oil recovery. These are seen to lie outside uncertainty bounds evaluated via the above mentioned MCbased analysis. Relying on the Stone formulations together with the Larsen and Skauge (1998) gas relative permeability model yields (a) values of ultimate field oil recovery comprised within MC uncertainty bound and (b) values of field gas-oil ratio (GOR) which are smaller than those obtained through the Baker model in conjunction with the Larsen and Skauge (1998) formulation, both results falling markedly outside the MCbased confidence interval. Our results document the effect that propagation of uncertainties from calibrating three-phase relative permeability model parameters can have on field-scale simulation outputs, such as ultimate oil recovery and field GOR. They also serve as a baseline against which simulation results based on typical procedures to model three-phase relative permeabilities can be assessed.
Modeling acid fracturing operations in carbonate formations is performed to evaluate the possible improvement in well productivity. Models are developed to mainly estimate the acid penetration length and the fracture surfaces etched-width profile. Variable combinations of these two parameters produce a significant difference in the fracture productivity. To better estimate these parameters, a reliable fracture propagation model should be coupled with the acid reaction/transport model. Simulating weak acids or dolomite formations reactivity requires the inclusion of a heat transfer model. The model provided in this study couples these factors as fractures propagate to finally obtain the fracture conductivity distribution along its length.
The fracture propagation model continuously updates the domain for the acid model. A transient acid convection and diffusion equation is solved and the fracture etched-width profile is calculated. An iterative procedure is implemented in a temperature dependent kinetic model which is stopped when both the temperature and acid solutions converge. When injection stops, acid etching and the fluids temperature are updated as the fracture closes. As the final etching profile is drawn, conductivity is calculated using a correlation that considers formation heterogeneity.
Coupling fracture propagation shows a significant difference on the acid model solutions compared to that assuming constant fracture geometry. For extremely high Peclet number that represents a very retarded acid system, a constant drop in the etched-width value until reaching zero at the fracture tip is theoretically obtainable. For lower Peclet numbers, the etching profile is shown to be sharply declining towards the fracture end. This is in contrast with the non-coupled approach from which a uniform etching profile is obtained at moderate to high Peclet numbers. It is also observed that the simulation of acid injection in non-coupled, constant fracture geometry always overestimates the acid penetration distance. The etched-width distribution and the acid penetration length are temperature sensitive, especially in dolomite formations. Temperature coupling shows that the maximum etching in dolomite formations occurs away from the fracture entrance as acid reactivity increases. It also shows that the cooling effects of the first stage pad fluid on improving the acid penetration distance is limited.
Simulating acid fracturing operations assuming constant final fracture geometry and an average single temperature is time efficient but results in inaccurate solution. This paper quantifies the effects of integrating fracture propagating and heat transfer models on the acid etching pattern from which, a better estimate of the fracture productivity is expected.
The document presents a consistent method to build 3D Mechanical Earth Models (3D MEM). It is based on a rock physics study to derive field specific correlations between mechanical properties and interpreted petrophysical quantities. The 3D MEMs built using this methodology yield robustness and consistency when matching to the measured minimum stress. They also display good predictive capabilities making them valuable for operational design.
This method consists of conducting a preliminary rock physics study in order to obtain correlations between the mechanical properties (elastic moduli and strength), of the various formations that are considered, and basic interpreted quantities which are readily available in most 3D geological models (porosity or mineralogy). The correlations are used to build a 3D MEM which is consistent with both the 3D geological model and the 1D geomechanical interpretation. It is also possible to extend the correlations by linking raw log data to rock mechanical properties.
The model was tested against field case study to verify its predictiveness. Minimum stresses calculated by the 3D MEM matched well to the measured values obtained from mini-frac tests performed at various locations. Ultimately it permits to better forecast the material properties (in 3D) as well as the effective stress tensor (in 4D). The 3D MEMs were used to evaluate the risks for infill drilling, and for completion purposes. Performing this type of preliminary rock physics study has a number of benefits. Firstly, to help identify which logging suite should be run to characterize the geomechanical properties of a given formation, and secondly it can be used to derive correlations between raw log data and geomechanical properties. These correlations can be applied during operations for real time decision making purposes when there is not yet a petrophysical interpretation available.
The novelty of the method introduced lies in the systematic and coherent integration of data to build a consistent geomechanical model (3D or 1D), that exhibits a robust predictive capability and shows the value of 3D MEM for the design of drilling and completion operations.
Detailed information of the near-well fluid flow is important for optimizing the production of hydrocarbons. In standard large-scale reservoir simulators the near-well physics are not captured, where the wells are usually represented by sink or source terms. The interaction between grid block pressure and well pressure is obtained with analytical solutions, which are tuned to match production history through a skin factor. Furthermore, in some commercial simulators the pressure loss in long horizontal wells are based on roughness calculations for flow in non-perforated pipes.
We demonstrate that by using Computational Fluid Dynamics (CFD) it is possible to obtain a detailed modeling of the near-well flow. The detailed simulations include the 3D trajectory of the well, completions, detailed reservoir information, etc… A simple benchmark case is shown to validate the CFD method against an analytical solution. The well SCA-11A in the Danish Siri Field is then modeled using CFD. Measured pressures are used as boundary conditions for the simulation, and the single phase fluid is represented using the reservoir fluid properties.
A significant pressure drop is observed resulting in a high production in the heel section. The toe section has a limited production.