Hybrid parallel iterative sparse linear solver framework for reservoir geomechanical and flow simulation

Chapter 14 - Reservoir Flow Simulation

This paper presents a case study where a full interaction between static reservoir modelling and flow simulation was performed to optimize the development plan of a carbonate Field in Abu Dhabi. Since no reliable seismic attributes could be extracted from the 3D seismic, coupled with the fact the reservoir had only a few wells, several geological scenarios were modeled using both deterministic and stochastic techniques. Sensitivities were performed on variogram ranges, deterministic trends and algorithms. The population of the model with petrophysical properties was carried out using reconciled log and core data in the crestal area of the Field and propagated downflank with the assistance of trends. The simulation of the porosity was done with Sequential Gaussian Simulation and for the permeability a co-simulation with porosity technique was applied. The results of 1D permeability simulation were also tried. Both approaches for permeability modelling were matched with the well test results. Due to the absence of SCAL data and the fact that the open-hole log saturations are not reliable (low resistivity pay in some intervals), an analog Sw curve had to be used. Two extreme Sw curves (min and max) were considered to cover the uncertainty. Different reservoir descriptions (geological/petrophysical scenarios) were subsequently flow simulated and the results evaluated against different development options. The selected models matched water cuts and reservoir pressures without the need for permeability multipliers. Finally, the results on new drilled wells (blind tests), namely log properties, PBU and injectivity test results, showed a good agreement with the models. The selected models were used to compare different patterns of development under multiple pressure support schemes (peripherical and updip water injection, gas vs. water injection, etc.). This paper calls for the importance of building different static models using different geostatistical parameters to address the static-dynamic uncertainties, instead of performing a large number of stochastic realizations.

A novel DFIT simulator comprising a 3D hydraulic fracturing model seamlessly coupled within one software with reservoir flow and geomechanical modeling is described and used to numerically analyze DFITs in unconventional reservoirs. This workflow involves history matching treatment or injection pressures (fracture propagation) and shut-in (fracture closure) pressures consistent with 3D growth of hydraulic fractures in the presence of pressure dependent leak-off. These are the same fundamental processes which characterize Dynamic Stimulated Reservoir Volume or DSRV growth (Sen et al., 2018, Min et al., 2018) and DFITs can therefore be used to get a better early prognosis on the potential of DSRV growth in a tight reservoir. This modular DFIT simulator iteratively couples a finite-difference reservoir simulation with a finite- element geomechanical modeling within one software and can therefore maintain important consistencies between fracture opening, propagation, closure and the stress dependent leak-off and permeability evolution inside the induced dynamic SRV. Both DFIT injection and closure processes are numerically modeled - and depending on which model parameters we choose to fix and which we perturb, we can preemptively estimate the potential for a successful stimulation and its possible dimensions. This estimate can be obtained at the early stages of a field /section development, before embarking on major drilling and completion campaigns, even in the absence of substantial production data. And it provides guidance for optimizing major fracturing design and well spacing. This approach is not reliant or bound by the assumptions underlying widely-used analytical DFIT analyzing methods, and is therefore more flexible and better captures the physics of stimulation in unconventional reservoirs. An early understanding of the key geomechanical metrics defining unconventional reservoir enhancement (DSRV effectiveness) allows us to build a directional relationship between fracturing parameters and post-fracture production without the need for an extended record of production trends. This speeds up the continuous learning and adaptive process of completion optimization involving pumped volumes, cluster spacing and well landing zones.

New Perspectives for 3D Visualization of Dynamic Reservoir Uncertainty

Summary This talk will explore the link between seismic rock physics and reservoir flow simulation models. How does rock physics interpretation uncertainty affect the flow simulator response? What are the sensitivities between rock physics model parameters and flow simulations? Two cases will be discussed: one where the well-log rock physics interpretation of facies can affect the static model that goes into the simulator, and another where the dynamic time-response of the simulator is influenced by the rock physics model parameters, thus impacting the interpretation of time-lapse seismic data used in seismic history matching.

Parallel iterative linear solvers for multistep Runge-Kutta methods

Fracture-vuggy reservoirs have multiple storage space with irregular geometry and various scales, the scales ranges from a few microns to tens of meters. There are many flow states in the reservoir, such as fluid flow in porous medium, free flow in cave and fractures. Physical simulation and conventional numerical simulation methods difficult to accurately describe the flow characteristics of such reservoirs. In this paper, we use two phase flow multi-scale pseudo-particle discrete calculation model for flow simulation of such reservoirs. This model characterised the surface tension through introducing a repulsion between two phase interfaces, simulated wettability by introducing the force of Lennard-Jones form. The results shows that this method can simulate fluid flow of such reservoir well, determined the types and distribution of macroscopic remaining oil with different fracture-cave combination, supplied basis for further development remaining oil of this kind of reservoirs. [Received: January 29, 2016; Accepted: June 7, 2017]

In this paper to the coupled hydrodynamic and geomechanical simulation is presented. The physical poroelastic problem is mathematically interpreted and is solved within numerical simulation of fluid flow in reservoir and corresponding deformation processes. Special theoretical methods and their implementation in practice are presented for the problem of geomechanical and filtration processes occurring in the case of naturally fractured medium. The proposed algorithm is realized via special software created within the study. The process of developing a three-dimensional numerical dynamical geomechanical model of oil and gas field characterized by naturally fractured rocks is considered. Effect of mechanical parameters on the production rates is analyzed using a set of computational models, the appropriate sections of oil and gas field. The effect of changes in the pore pressure on the collector conductivity and ultimately on the characteristics of the production well is investigated.

It is now possible to integrate WITSML rig-issued well data, such as trajectory and associated raw measurements, and well analysis results stored in other data formats, including PPDM, into the RESQML set of data-objects that comprise the description of a reservoir or "Earth Model". It is now also possible to update the model as it is refined, through the life of a field. To develop this integration, the RESQML and WITSML Special Interest Groups (SIG) of Energistics formed a Wells sub-group for the current RESQML version 2 (V2) development cycle. The sub-group is focusing on using the current WITSML V1.4.1.1 data model to abstract a simplified WITSML well consisting of three fundamental objects: its trajectory, either in depth and/or in time; a"WellboreFrame", which is used to reference the WITSML log data; and its extension to reference WITSML marker data. These objects reference WITSML but now exist in the RESQML data model, which allows them to access existing RESQML capabilities. Through this unified vision, the RESQML V2 data standard will allow drillers and production engineers to seamlessly access reservoir characterization and simulation results, and allow the reservoir engineers to benefit from the entire range of well-based drilling, petrophysical, and production data within an integrated team. This paper presents how the RESQML V2 design allows association of WITSML and RESQML dedicated objects, and how to establish the relationships between these new objects and the structural, stratigraphic, and reservoir elements inside a RESQML model. In part, this integration has been enabled by the new Energistics Open Packaging Conventions (EPC), which allows multiple data standards (not only RESQML and WITSML) to be recognized and managed consistently. This integration provides the foundation for future RESQML work, including plans to integrate the WITSML Completion data-object, and seismic data (represented in either time or space), both in the reservoir and at the wells.

We have undertaken a simplified calculation of orbital forcing back through the Cretaceous to the Late to Middle Jurassic from 65 to 190 Ma. So long as the Earth has a continental ice volume, orbital forcing will impose a 400-ky periodicity upon glacioeustasy and thereby on fourth-order sequence stratigraphy cycles. Similarly, third-order cycles were defined by orbital forcing of 2.4 ± 0.4 my (predominately 2.0- and 2.8-my cycles). These concepts greatly simplified the task of unraveling sequence stratigraphy. Our sea-level calculations are comparable with stratigraphic observations and the results are consistent with a persistent continental ice volume throughout the Late to Middle Jurassic and Cretaceous. In general, they compare well with the Arabian Plate Maximum Flooding Surfaces and the Cretaceous and Jurassic stage boundaries, within the limits of the recognized stratigraphic time scales. We used simple Parametric Forward Models (PFMs) for modeling changes in sea level, subsidence, and sedimentation and noted that PFMs can be applied to other tasks. The results will provide for rapid, cost-effective forward modeling on tasks such as reservoir characterization and flow simulation.

The objective of this project is to demonstrate that detailed reservoir characterization of slope and basin clastic reservoirs in sandstones of the Delaware Mountain Group in the Delaware Basin of West Texas and New mexico is a cost-effective way to recover a higher percentage of the original oil in place through strategic placement of infill wells and geologically based field development. Project objectives are divided into two major phases. The objectives of the reservoir characterization phase of the project are to provide a detailed understanding of the architecture and heterogeneity of two fields, the Ford Geraldine Unit and Ford West field, which produce from the Bell Canyon and Cherry Canyon Formations, respectively, of the Delaware Mountain Group and to compare Bell Canyon and Cherry Canyon reservoirs. Reservoir characterization will utilize 3-D seismic data, high-resolution sequence stratigraphy, subsurface field studies, outcrop characterization, and other techniques. Once the reservoir characterization study of both fields is completed, a pilot area of approximately 1 mi{sup 2} in one of the fields will be chosen for reservoir simulation. The objectives of the implementation phase of the project are to (1) apply the knowledge gained from reservoir characterization and simulation studies to increase recovery from the pilot area, (2) demonstrate that economically significant unrecovered oil remains in geologically resolvable untapped compartments, and (3) test the accuracy of reservoir characterization and flow simulation as predictive tools in resource preservation of mature fields. A geologically designed, enhanced recovery program (CO{sub 2} flood, waterflood, or polymer flood) and well-completion program will be developed, and one to three infill wells will be drilled and cored.

The objective of this project is to demonstrate that detailed reservoir characterization of slope and basin clastic reservoirs in sandstones of the Delaware Mountain Group in the Delaware Basin of West Texas and New Mexico is a cost effective way to recover a higher percentage of the original oil in place through strategic placement of infill wells and geologically based field development. Project objectives are divided into two major phases. The objectives of the reservoir characterization phase of the project are to provide a detailed understanding of the architecture and heterogeneity of two fields, the Ford Geraldine unit and Ford West field, which produce from the Bell Canyon and Cherry Canyon Formations, respectively, of the Delaware Mountain Group and to compare Bell Canyon and Cherry Canyon reservoirs. Reservoir characterization will utilize 3-D seismic data, high-resolution sequence stratigraphy, subsurface field studies, outcrop characterization, and other techniques. Once the reservoir- characterization study of both fields is completed, a pilot area of approximately 1 mi{sup 2} in one of the fields will be chosen for reservoir simulation. The objectives of the implementation phase of the project are to (1) apply the knowledge gained from reservoir characterization and simulation studies to increase recovery from the pilot area, (2) demonstrate that economically significant unrecovered oil remains in geologically resolvable untapped compartments, and (3) test the accuracy of reservoir characterization and flow simulation as predictive tools in resource preservation of mature fields. A geologically designed, enhanced-recovery program (CO{sub 2} flood, waterflood, or polymer flood) and well-completion program will be developed, and one to three infill wells will be drilled and cored. Progress to date is summarized for reservoir characterization.

Estimation of permeability of naturally fractured reservoirs by pressure transient analysis: An innovative reservoir characterization and flow simulation

The objective of this project is to demonstrate that detailed reservoir characterization of slope and basin clastic reservoirs in sandstones of the Delaware Mountain Group in the Delaware Basin of West Texas and New Mexico is a cost effective way to recover a higher percentage of the original oil in place through strategic placement of infill wells and geologically based field development. Project objectives are divided into two major phases. The objectives of the reservoir characterization phase of the project are to provide a detailed understanding of the architecture and heterogeneity of two fields, the Ford Geraldine unit and Ford West field, which produce from the Bell Canyon and Cherry Canyon Formations, respectively, of the Delaware Mountain Group and to compare Bell Canyon and Cherry Canyon reservoirs. Reservoir characterization will utilize 3-D seismic data, high-resolution sequence stratigraphy, subsurface field studies, outcrop characterization, and other techniques. Once the reservoir- characterization study of both fields is completed, a pilot area of approximately 1 mi{sup 2} in one of the fields will be chosen for reservoir simulation. The objectives of the implementation phase of the project are to (1) apply the knowledge gained from reservoir characterization and simulation studies to increase recovery from the pilot area, (2) demonstrate that economically significant unrecovered oil remains in geologically resolvable untapped compartments, and (3) test the accuracy of reservoir characterization and flow simulation as predictive tools in resource preservation of mature fields. A geologically designed, enhanced-recovery program (CO{sup 2} flood, waterflood, or polymer flood) and well-completion program will be developed, and one to three infill wells will be drilled and cored. Accomplishments for this past quarter are discussed.

Fracturing modeling methods developed for conventional hydraulic fracturing are now being used for unconventional fracturing in waterfracs, water or steam flooding, produced water reinjection, etc. A common feature of these unconventional fracturing processes is the strong interaction among fracture propagation (often with high 3D fluid leakoff), reservoir flow, changes in stresses (poroelastic and thermoelastic effects), and permeability and porosity changes (geomechanical effects) around the fracture. Conventional fracturing models are inadequate under such conditions; moreover, they are also disconnected from well performance forecasting, which makes integrated data analysis difficult. Therefore, it is necessary to seek a new modeling concept including all these mechanisms and their mutual influences. This paper describes a method to model hydraulic fracturing with dynamic transmissibility multipliers based on coupled reservoir and geomechanics simulation. The method is the first step in developing a fracturing model fully coupled into reservoir and geomechanics simulation, where the fracture geometry will be also internally calculated from the fracture face displacements in the coupled FEM geomechanical module. The method described here ignores fracture volume but focuses on the effect of fracture on fluid flow and geomechanics in reservoir by introducing pressure/stress dependent dynamic transmissibility multipliers and treating them as a property of the matrix. This approach allows modeling fracture propagation, dynamical multiphase fracture conductivity, clean-up, and pre- and post-frac well performance in a changing stress, pressure and temperature environment, all in a unified manner. This paper also discusses the strategy of coupling hydraulic fracture propagation, reservoir and geomchanics simulation, resulting in a method to improve the stability of the dynamic hydraulic fracture propagation in coupled reservoir and geomechanics simulation. The case studies in this paper confirm that the strategy and the method to model dynamic hydraulic fracture propagation coupled with reservoir and geomechanics simulation is feasible, flexible and reliable. It is easy and convenient to implement in conventional reservoir simulators and coupled reservoir and geomechanics simulators (such as GEOSIM).