Reliability of subsurface assessment for different field development scenarios depends on how effective the uncertainty in production forecast is quantified. Currently there is a body of work in the literature on different methods to quantify the uncertainty in production forecast. The objective of this paper is to revisit and compare these probabilistic uncertainty quantification techniques through their applications to assisted history matching of a deep-water offshore waterflood field. The paper will address the benefits, limitations, and the best criteria for applicability of each technique.
Three probabilistic history matching techniques commonly practiced in the industry are discussed. These are Design-of-Experiment (DoE) with rejection sampling from proxy, Ensemble Smoother (ES) and Genetic Algorithm (GA). The model used for this study is an offshore waterflood field in Gulf-of-Mexico. Posterior distributions of global subsurface uncertainties (e.g. regional pore volume and oil-water contact) were estimated using each technique conditioned to the injection and production data.
The three probabilistic history matching techniques were applied to a deep-water field with 13 years of production history. The first 8 years of production data was used for the history matching and estimate of the posterior distribution of uncertainty in geologic parameters. While the convergence behavior and shape of the posterior distributions were different, consistent posterior means were obtained from Bayesian workflows such as DoE or ES. In contrast, the application of GA showed differences in posterior distribution of geological uncertainty parameters, especially those that had small sensitivity to the production data. We then conducted production forecast by including infill wells and evaluated the production performance using sample means of posterior geologic uncertainty parameters. The robustness of the solution was examined by performing history matching multiple times using different initial sample points (e.g. random seed). This confirmed that heuristic optimization techniques such as GA were unstable since parameter setup for the optimizer had a large impact on uncertainty characterization and production performance.
This study shows the guideline to obtain the stable solution from the history matching techniques used for different conditions such as number of simulation model realizations and uncertainty parameters, and number of datapoints (e.g. maturity of the reservoir development). These guidelines will greatly help the decision-making process in selection of best development options.
Maleki, Masoud (Uuniversity of Campinas UNICAMP) | Danaei, Shahram (Uuniversity of Campinas UNICAMP) | Davolio, Alessandra (Uuniversity of Campinas UNICAMP) | José Schiozer, Denis (Uuniversity of Campinas UNICAMP)
Permanent Reservoir Monitoring (PRM) in systems deep-water settings provide on-demand snapshots for hydrocarbon reservoirs at different times during their production history. Delays in the interpretation turnaround of 4D seismic data reduce some benefits of the PRM. These delays could adversely impact the decision making processes despite obtaining information on demand. Using fast-track approaches in 4D seismic interpretation can provide timely information for reservoir management. This work focuses on a fast-track 4D seismic qualitative interpretation in PRM environment, with the aim of choosing the best seismic amplitude attribute (4D) to use. Different seismic attributes are extracted and the one with high signal-to-noise ratio is selected to carry out the 4D qualitative interpretation. All 4D signals are juxtaposed with well production history data to increase confidence in our interpretation. The selected attribute can be interpreted and used for the foreseeable life of field. This workflow has been developed and applied on post-salt Brazilian offshore field to choose the best seismic attribute to conduct the 4D seismic qualitative interpretation.
Hjeij, Dawood (Division of Sustainable Development, College of Science and Engineering, Hamad Bin Khalifa University) | Abushaikha, Ahmad (Division of Sustainable Development, College of Science and Engineering, Hamad Bin Khalifa University)
Most commercially available simulators use the trivial two-point flux approximation (TPFA) method for flux computation. However, the TPFA only gives consistent solutions when used for K-orthogonal grids. In general, multi-point flux approximation (MPFA) methods perform better under both heterogeneous and anisotropic conditions. The mimetic finite difference (MFD) method is designed to preserve properties on unstructured polyhedral grids, and its development for simulating full tensor permeabilities is also crucial step. This paper compares the performance, accuracy, and efficiency of these schemes for simulating complex synthetic and realistic hydrocarbon reservoirs.
A challenging problem of automated history-matching work flows is ensuring that, after applying updates to previous models, the resulting history-matched models remain consistent geologically. To enhance the applicability of localization to various history-matching problems, the authors adopt an adaptive localization scheme that exploits the correlations between model variables and observations. This paper presents a novel approach to generate approximate conditional realizations using the distributed Gauss-Newton (DGN) method together with a multiple local Gaussian approximation technique. This work presents a systematic and rigorous approach of reservoir decomposition combined with the ensemble Kalman smoother to overcome the complexity and computational burden associated with history matching field-scale reservoirs in the Middle East. This paper presents a comparison of existing work flows and introduces a practically driven approach, referred to as “drill and learn,” using elements and concepts from existing work flows to quantify the value of learning (VOL).
In need of an exploration boost, Norway doled out a record 83 production licenses in mature areas of the Norwegian Continental Shelf to 33 firms. Norway hopes for a continued rise in offshore exploration and development activity to ensure steady oil and gas production through the next decade. Equinor has grabbed seven new licenses in the Barents and Norwegian Seas, the latest in a flurry of offshore activity in which the firm has added acreage off the UK and Brazil, gained approval for a big Arctic project, and awarded billions of dollars in service contracts. A reservoir-conditions coreflood study was undertaken to assist with design of drilling and completion fluids for a Norwegian field. Multiple fluids were tested, and the lowest permeability alterations did not correlate with the lowest drilling-fluid-filtrate-loss volumes.
High-resolution discretizations can be advantageous in compositional simulation to reduce excessive numerical diffusion that tends to mask shocks and fingering effects. In this work, we outline a fully implicit, dynamic, multilevel, high-resolution simulator for compositional problems on unstructured polyhedral grids. We rely on four ingredients: (i) sequential splitting of the full problem into a pressure and a transport problem, (ii) ordering of grid cells based on intercell fluxes to localize the nonlinear transport solves, (iii) higher-order discontinuous Galerkin (dG) spatial discretization with order adaptivity for the component transport, and (iv) a dynamic coarsening and refinement procedure. For purely cocurrent flow, and in the absence of capillary forces, the nonlinear transport system can be perturbed to a lower block-triangular form. With counter-current flow caused by gravity or capillary forces, the nonlinear system of discrete transport equations will contain larger blocks of mutually dependent cells on the diagonal. In either case, the transport subproblem can be solved efficiently cell-by-cell or block-by-block because of the natural localization in the dG scheme. In addition, we discuss how adaptive grid and order refinement can effectively improve accuracy. We demonstrate the applicability of the proposed solver through a number of examples, ranging from simple conceptual problems with PEBI grids in two dimensions, to realistic reservoir models in three dimensions. We compare our new solver to the standard upstream-mobility-weighting scheme and to a second-order WENO scheme.
As the oil and gas industry continues to operate in more complex and deeper water environments downhole scale control via scale squeeze treatments becomes an ever-increasing technical challenge. It is therefore essential that effective scale management strategies are adopted which incorporate suitable scale inhibitor (SI) selection, analysis and treatment design procedures to provide optimal and cost-effective squeeze treatment lifetimes to maximise oil production and reduce well intervention costs.
In this paper key factors are evaluated in order to provide a guidance to selecting a suitable treatment strategy for downhole scale control in co-mingled sub-sea well and the impact of chemical retention, minimum inhibitor concentration (MIC), limit of quantifiable detection (LOQD) and well dilution factors on treatment design and strategy are discussed. The pros and cons of different treatment strategies are presented in this paper and consideration is given to following three treatment strategies: Treating all wells with the same chemical and over designing the chemical treatment lifetime ie 18 months and then re-treating all wells after 12 months; Treating individual wells with tagged versions of the same scale inhibitor chemical; Treating individual wells with different scale inhibitors.
Treating all wells with the same chemical and over designing the chemical treatment lifetime ie 18 months and then re-treating all wells after 12 months;
Treating individual wells with tagged versions of the same scale inhibitor chemical;
Treating individual wells with different scale inhibitors.
Options (ii) and (iii) offer the ability to design similar treatment lifetimes for each well but have the flexibility to monitor wells individually and re-squeeze when required.
Examples are provided for treatment options (ii) and (iii) based upon a field example to illustrate the design concepts for fluorescent (F) and phosphorus (P) tagged polymers in two co-mingled wells and a theoretical example for treating three co-mingled wells with different scale inhibitors, one of which could be a phosphonate with two tagged polymers.
This paper presents an overview of the key factors that influence chemical selection and treatment design for co-mingled wells in the same flow line. In addition, it will highlight important concepts to provide guidance for the design of effective treatment strategies for squeezing co-mingled wells in sub-sea and deepwater environments.
Accurate numerical modeling of fluid transport is essential in reservoir management. Higher-order methods help to improve accuracy by reducing the numerical diffusion, which is common for all first order methods. In this paper, we present an implementation of a MUSCL-type second-order finite volume method and demonstrate its capabilities on 2D and 3D unstructured grids. This includes corner point grids that are typically used in reservoir modeling.
A second order finite volume method is compared to standard first order method in terms of accuracy, performance and an ability to handle nonlinearities. There are several ways to build a second order finite volume method. In this paper we choose an optimization-based strategy to compute the steepest possible linear reconstruction. At the same time, a steepness-limiting procedure is included in the optimization as constraint. This ensures that the steepest possible reconstruction that does not lead to oscillations is computed. As a result, sharper fronts compared to standard schemes are obtained.
The paper demonstrates the described method on several benchmark cases with emphasis on relevant for practical reservoir simulation test cases. In particular, we use Norne field open data set, which enables cross validation with other implementations. We test the method on the transport case, where an analytical solution is known, to verify convergence behavior and to isolate the errors. Furthermore, the performance of first- and second-order methods is compared on multiphase flow problems typical for improved oil recovery: solvent and CO2 injection. The second order method shows superior performance in terms of accuracy.
This paper verifies the desirable properties of higher order method for reservoir simulation. Moreover, all the described implementations are available in an open source reservoir simulator Open Porous Media (OPM). As a result, these methods are accessible for reservoir engineers and can be used with industry standard modeling setups.
Modelling multiscale-multiphysics geology at field scales is non-trivial due to computational resources and data availability. At such scales it is common to use implicit modelling approaches as they remain a practical method of understanding the first order processes of complex systems. In this work we introduce a numerical framework for the simulation of geomechanical dual-continuum materials. Our framework is written as part of the open source MATLAB Reservoir Simulation Toolbox (MRST). We discretise the flow and mechanics problems using the finite volume method (FVM) and virtual element method (VEM) respectively. The result is a framework that ensures local mass conservation with respect to flow and is robust with respect to gridding. Solution of the coupled linear system can be achieved with either fully coupled or fixed-stress split solution strategies. We demonstrate our framework on an analytical comparison case and on a 3D geological grid case. In the former we observe a good match between analytical and numerical results, for both fully coupled and fixed-stress split strategies. In the latter, the geological model is gridded using a corner point grid that contains degenerate cells as well as hanging nodes. For the geological case, we observe physically plausible and intuitive results given the boundary conditions of the problem. Our initial testing with the framework suggests that the FEM-VEM discretisation has potential for conducting practical geomechanical studies of multiscale systems.
Scale inhibitor (SI) analysis is an extremely important part of scale management and, in recent years, much work has been done on the development of specialist scale inhibitor analysis techniques like Liquid Chromatography Mass Spectroscopy (LCMS) to push the boundaries of low level scale inhibitor detection. However, LCMS requires costly and complex instrumentation and there was therefore still a need for the development of other advanced techniques like fluorescence (F) and Time resolved Fluorescence (TRF) that can be used on site to provide near "on line" data.
Fluorescence techniques are particularly suited to tagged polymers and naturally fluorescent molecules like polyamines whereas the operation principle of TRF is based on interactions between lanthanide ions and various functional groups of polymer or phosphonate scale inhibitors.
Both techniques work individually or in combination and this provides a distinct advantage for multiple scale inhibitor analysis in produced brines that enable the design of packages of different products for specific field applications. In addition, TRF and fluorescence techniques offer the capability of on-site detection compared to the majority of scale inhibitor analysis techniques and other advanced methods like LC-MS.
The ability to detect both phosphonate and polymeric scale inhibitors at very low MIC (<1ppm) has the potential for significantly extending scale squeeze lifetimes. This has now also allowed highly efficient, F tagged polymers, to be used in field situations where scale squeezing was either stopped or the lifetime was significantly compromised because of the lack of confidence in the residuals analysis.
Specific field and theoretical examples from both sub-sea and conventional wells will be presented where the application of both advanced fluorescence and TRF techniques has shown significant improvements in scale management.
This paper will compare and contrast the pros, cons and limitations of both fluorescence and TRF techniques for both phosphonate and polymeric scale inhibitors. In addition, it will highlight examples where scale management significantly improves through the application of Fluorescence and/or TRF scale inhibitor analysis techniques in complex production scenarios.