Near-wellbore Modeling Research Articles

Poromechanics Modeling Forecasts Production, Analyzes Productivity Decline

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 212200, “Accurate Production Forecasting and Productivity Decline Analysis Using Coupled Full-Field and Near-Wellbore Poromechanics Modeling,” by Yan Li, Bin Wang, and Jiehao Wang, Chevron, et al. The paper has not been peer reviewed. _ Productivity index (PI) decline is caused by different mechanisms in both the wellbore region and the far field. Damage in the wellbore region can be simulated by detailed wellbore modeling. A newly developed full-field and near-wellbore poromechanics coupling scheme is used in the complete paper to model PI degradation against time. Near-wellbore damage and field and well interactions are identified when applying the coupling scheme for a deepwater well. History matching, production forecasting, and safe drawdown limits are derived for operational decisions. Full-Field Reservoir Model and Near-Wellbore Poromechanics Model Coupling Full-field and near-wellbore modeling involves coupling the simulation of a full-field reservoir model with one or more near-wellbore poromechanics models. In the coupled simulation, the full-field reservoir model dictates the changing flow or thermal boundary conditions for the embedded near-wellbore models. Meanwhile, near-wellbore phenomena affect well productivity in the full-field reservoir model, altering the flow and thermal boundary conditions on all near-wellbore models in the same field. While capturing the dynamic interactions between the full-field model and all embedded near-wellbore models is of vital importance, the traditional near-wellbore modeling work flow considers only one-way coupling. This work flow is labor-intensive and lacks the dynamic interplay between the reservoir and near-wellbore models. A novel near-wellbore coupling framework is developed to automate data exchange and capture dynamic interactions between the full-field model and the near-wellbore model. In the full-field reservoir and geomechanics coupling applications, only a reservoir simulator solves reservoir flow and thermal equations and a geomechanics simulator solves solid mechanics equations. The reservoir and geomechanics simulators exchange 3D field data. Because solid mechanics equations are quasistatic, the geomechanics simulator does not take timesteps in full-field coupling. In near-wellbore coupling, however, both reservoir and geomechanics simulators solve reservoir flow and thermal equations. The near-wellbore geomechanics model also may solve solid mechanics or other equations coupled to flow or thermal equations in the near-wellbore model. All physics are included in the near-wellbore model for the coupling. Both field properties (3D) and transient boundary conditions (2D) must be mapped onto the near-wellbore model. It is important to ensure that the full-field and near-wellbore models are consistent. A 3D data-mapping module is developed to map flow and rock properties and initial conditions from the full-field model to the near-wellbore model. During the simulation, the transient pressure/temperature boundary conditions (2D) at the external boundary of the near-wellbore model must be mapped from the full-field model to the near-wellbore model to update transient boundary conditions. The automated data mapping in the coupling scheme eliminates the need for manual mapping of field properties and transient boundary conditions.

Near-wellbore modeling of a horizontal well with Computational Fluid Dynamics

The oil production by horizontal wells is a complex phenomenon that involves flow through the porous reservoir, completion interface and the well itself. Conventional reservoir simulators can hardly resolve the flow through the completion into the wellbore. On the contrary, Computational Fluid Dynamics (CFD) is capable of modeling the complex interaction between the creeping reservoir flow and turbulent well flow for single phases, while capturing both the completion geometry and formation damage. A series of single phase steady-state simulations are undertaken, using such fully coupled three dimensional numerical models, to predict the inflow to the well. The present study considers the applicability of CFD for near-wellbore modeling through benchmark cases with available analytical solutions. Moreover, single phase steady-state numerical investigations are performed on a specific perforated horizontal well producing from the Siri field, offshore Denmark. The performance of the well is investigated with an emphasis on the inflow profile and the productivity index for different formation damage scenarios. A considerable redistribution of the inflow profile were found when the filtrate invasion extended beyond the tip of the perforations.

Improving fracture initiation predictions of a horizontal wellbore in laminated anisotropy shales

Increasingly prominent unconventional petroleum resources tend to occur in formations with laminated heterogeneity. The predominant laminated heterogeneity in tight gas shale reservoirs results in considerable variability in the elastic properties along the orientations parallel and perpendicular to the bedding direction.By incorporating the anisotropic elastic deformation and pore hydro-mechanical coupling effects, a 3D numerical model of fracture initiation from a perforated horizontal wellbore is established. A sensitivity analysis is proposed to evaluate the effects of the anisotropic mechanical behavior and in situ stress conditions on the fracture initiation pressure (FIP) and location of an initial rupture. Comprehensive analysis results revealed elastic anisotropy results in the complex near-wellbore stress concentrations, proved by the fact that the near wellbore fracture tortuosity increases as the perforation azimuth increases, which is not observed in traditional isotropic rocks. Furthermore, perforation parameters including perforation density, perforation diameter, and perforation depth, are also analyzed assuming elastic anisotropy conditions. In addition, a stronger Young's modulus anisotropy causes lower fracture initiation pressure and lower fracture tortuosity at the wellbore face, while the impact of the Poisson's ratio anisotropy is relatively small. Changes in the in situ stress conditions have a significant effect on the fracture initiation pressure whether the rock is an isotropic or anisotropic formation. Numerical simulation results indicate that near-wellbore modeling in horizontal completions in an anisotropic shale is a necessary step for predicting and controlling the potential problems during fracturing treatment and avoiding erroneous completion decisions based on traditional isotropic models.

Reservoir Simulation, Ion Reactions, and Near-Wellbore Modeling To Aid Scale Management in a Subsea Gulf of Mexico Field

Summary This paper presents the findings of a study into the impact of reservoir flow behavior on the scaling risk at production wells and the options for managing this scaling risk for a deepwater sandstone reservoir in the Gulf of Mexico. One significant feature in this field is that flow takes place through isolated formation layers, and choices made regarding the seawater-injection wells have a great impact, not only on the barium sulfate (BaSO4) scaling tendency, but also on the placement of scale-inhibitor squeeze treatments in the producers. In addition to seawater injection, oil production is supported by the aquifer. The first stage of this study involved identifying the split between connate water, aquifer water, and seawater in the produced brine. This provided data that could be used to calculate the evolution of the scaling risk over the life cycle of each well. The formation brines contained barium, the injection water was full-sulfate seawater, and the relative proportion of brine (the water-production rate, pressure, and temperature conditions) determined the scaling risk. The evaluation of the extent of reactions between the injection water (sulfate) and formation water (barium) from injection to production well can result in a significant reduction in the available barium within the produced water, and hence, the scaling risk and scale-inhibitor concentration required for prevention of scale deposition. In this study, because the injection wells were completed with inflow-control valves (ICVs), the opportunity was given to manage the injection split by means of these ICVs, not only to improve sweep efficiency, but also to balance reservoir pressures and make squeeze treatments more efficient. This study will present the squeeze-treatment volumes and estimated treatment lifetimes possible for two scenarios for the water-injection application to this deepwater field. The implications of this type of study will be highlighted in terms of the options that these data will allow an operator to consider before commissioning water injection in these challenging environments.

Improving Reservoir Characterization and Simulation With Near-Wellbore Modeling

SummaryNew reservoir characterization methods are needed to integrate multiscale exploration and development data, particularly at the interface between well and field models. In this paper, we illustrate a novel workflow involving high-resolution near-wellbore modeling (NWM), which allows us to accurately include seismic, wireline data, image logs, and well core logs from highly heterogeneous reservoirs in field-scale reservoir simulations. We demonstrate that an NWM-enhanced geoengineering workflow has the potential to improve reservoir characterization by applying it to a realistic clastic reservoir with high variance at small scale. We have performed a number of sensitivities comparing conventional local grid refinement (LGR) in the near-wellbore region with that involving NWM, and we obtained a significant increase in the accuracy of reservoir characterization and the calibration of dynamic models. Centimeter-scale models, containing several million cells, representing the fine geological details of the near-wellbore region, were constructed with available data from core and openhole well-log suits. The resulting well models were upscaled into regular grids with the highest resolution possible through the NWM software and incorporated into a field-scale simulation model to evaluate the dynamic behavior of the reservoir with a static-model transient test. Our results show that the use of NWM tools for reservoir modeling yields more precise flow calculations and improves our fundamental understanding of the interactions between the reservoir and the wellbore.

Near-Wellbore Modeling: Sand-Production Issues

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 109894, "Near-Wellbore Modeling: Sand-Production Issues," by Guillaume Servant, IFP; Philippe Marchina, SPE, Total; and Jean- Francois Nauroy, IFP, prepared for the 2007 SPE Annual Technical Conference and Exhibition, Anaheim, California, 11-14 November 2007. The paper has not been peer reviewed. Sand production in an oil or gas well can cause operational difficulties, but it contributes to production enhancement by improving the well inflow performance. To assess the relative magnitude of those effects and to optimize the well completion and operation, a quantitative forecast of the expected amount and rate of sand production must be made. This forecast requires a correct description of all the mechanisms involved in sand production, sand transport in particular. The proposed numerical method considers that the geomechanical problem (rock failure) interplays with the transport of sand. Equilibrium equations that control rock failure (solid mechanics) and sand transport (fluid mechanics) are solved simultaneously by an iterative coupled scheme at the wellbore scale. Introduction Sand production causes production problems and can generate safety and environmental hazards. However, it can increase the inflow performance of the well. Therefore, the option of installing downhole sand-control equipment may not always be the best economic solution for the project. Heavy-oil reservoirs can benefit from allowing sand to be produced with the oil. This technique, known as cold-heavy-oil production with sand (CHOPS), allows higher production rates than conventional techniques. Again, the productivity and ultimate delivery of the well will depend on the amount of sand produced. Therefore, the ability to anticipate the sand-production mechanisms in terms of sand rate and volumes, and anticipate sand-producing patterns in the reservoir, is required for optimized development of such fields. Two mechanisms contribute to sand production: rock failure (through which freed sand grains are generated) and transport of those free grains by the effluents into the wellbore and up to surface. Most current sand-production-risk models concentrate on the rock-failure analysis and, as such, can determine only the conditions for the onset of sand production. In the proposed model, the rock-mechanical aspects are coupled to the sand-transport problem. Therefore, interaction between the solid matrix and the slurry flow can be analyzed and translated into quantitative sand production. Paralleling development of this numerical model, a series of sand-production experiments was carried out in a purpose-built laboratory apparatus with the objectives of understanding the sand-production processes in uncemented reservoirs better and providing high-quality data sets for calibrating the model.

Technology Focus: Wellbore Integrity, Sand Management, and Frac Pack (September 2008)

Technology Focus This year's focus is on the completion. A paper on near-wellbore modeling of sand-production behavior provides well engineers a glimpse into the world of cutting-edge rock-failure forecasting. The paper provides engineering practitioners valuable insight into the challenge of predicting produced-sand rates on a fieldwide scale. A second paper incorporates sand failure and produced-solids-transport fore-casts with the effects on surface facilities and production by use of a probabilistic approach to manage the uncertainties. This work provides a framework that may be used to move innovative reservoir- and production-systems failure models to the fieldwide level, which is necessary for asset management. The goal is to characterize the asset-development-plan cycle from appraisal through abandonment. A third paper presents a possible solution to the proppant-flowback problem associated with screenless frac-pack completions. The approach involves resin coating of the proppant during pumping, and a convincing argument is presented supporting induced-fracture-conductivity preservation after placement. For deepwater completions, this issue can be extraordinarily expensive and is a very real concern when evaluating risk in completion-design alternatives. A common theme among these papers deals with the challenge of scaling up laboratory learnings to field-development practice. Today's multidiscipline-team approach to field development can provide the connection needed to foster an awareness of the effect of diverse laboratory-measurement data on asset-development viability. Wellbore Integrity, Sand Management, and Frac-Pack additional reading available at the SPE eLibrary: www.spe.org IPTC 11472 • "Mechanical-Earth-Model Calibration for Sanding-Potential Estimation: A Case Study From the Tombua-Landana Development in Angola's Deepwater Block 14" by Peng L. Ray, SPE, Chevron, et al. SPE 109662 • "Enhanced Mechanical Earth Modeling and Wellbore-Stability Calculations Using Advanced Sonic Measurements—A Case Study of the HP/HT Kvitebjorn Field in the Norwegian North Sea" by Anke S. Wendt, SPE, Schlumberger, et al.

Special Issue

Formation damage refers to the impairment of petroleum-bearing formations by various adverse phenomena occurring in a manner to reduce the recovery of oil and gas from petroleum reservoirs. Evaluation and mitigation of formation damage in petroleum reservoirs are among the issues of primary interest for the operators in order to accomplish the economically effective production strategies during the productive life of petroleum reservoirs and to maximize the ultimate oil and gas recovery. However, circumventing the formation damage problems is a highly challenging undertaking because the formation damage phenomena involve many inherently complex interaction processes between the operation conditions and configuration of wells, the reservoir and externally-introduced fluids and particulate matter, and the constituents and conditions of the petroleum-bearing formations. This special issue presents ten papers providing information on the recent advancements made in the experimental, theoretical, and field understanding of the practical formation damage issues and the optimal measures and strategies considered for controlling and minimizing the reservoir formation damage.J. M. Schembre and A. R. Kovscek carry out laboratory core tests, apply the theory of colloidal stability, and demonstrate that high temperature, alkaline, and pH, and low salinity conditions induce fines mobilization and permeability reduction in Berea sandstones.A. Hayatdavoudi explains that the water hammer phenomenon created during the various injection and production operations may cause the sand liquefaction and production. The pressure wave-induced acceleration of the sand particles is shown to be highly sensitive to the water level variation and/or water encroachment in unconsolidated sand formations.K. J. Leontaritis presents a model for the near-well formation damage caused as a result of pore throat plugging by asphaltene particles during oil production. This model incorporates the thermodynamic-colloidal model of asphaltene in oil and an asphaltene phase behavior model for prediction of the asphaltene particle size distribution and its affect under the prevailing fluid conditions.E. J. Mackay and M. M. Jordan describe the scaling potential and formation damage due to precipitation of inorganic scales during conventional waterflooding in deepwater regions associated with the offshore production environments. The various risk management strategies for effective scale control are reviewed by means of reservoir simulation.H. A. Nasr-El-Din discusses the measures required to minimize and control the various formation damage problems caused by the common chemical treatment techniques originally designed to remove the particular formation damage problems.C. Li, T. Xie, M. Pournik, D. Zhu, and A. D. Hill apply a fine-scale model for the sandstone core acid flooding process by numerically solving the acid and mineral balance equations for a three-dimensional flow field. The reservoir heterogeneities are shown to cause the acid to penetrate much farther from the injection face into the formation than for a homogeneous case.G. Penny, J. T. Pursley, and D. Holcomb demonstrate by laboratory core tests and field examples that a new microemulsion additive helps for effective cleanup of injected fluids in tight gas formations. The applications involving the remediation and fracture treating of coals, shales, and sandstone reservoirs result in lower formation damage and higher production rates.D. B. Bennion and F. B. Thomas review the formation damage mechanisms associated with very low in-situ permeability gas reservoir formations, emphasizing on the relative permeability and capillary pressure effects leading to phase trapping. The challenges encountered during the drilling and completion practices in order to minimize the impact of formation damage on the well productivity are described.H. Jahediesfanjani and F. Civan investigate the damage tolerance of the conventional well-completion and stimulation techniques in reducing the formation damage effects and increasing the productivity of the coalbed methane reservoirs. The efficiency and performance of the openhole cavity completions, hydraulic fracturing, frack and packs, and horizontal wells are compared with a nondamaged vertical well in terms of the normalized productivity index.Y. Ding and G. Renard present an integrated approach for evaluation of the performance of oil and gas wells after drilling induced formation damage by means of a near-wellbore modeling using the input data obtained by laboratory tests.

Evaluation of Horizontal Well Performance After Drilling-Induced Formation Damage

It is well recognized that near-wellbore formation damage can dramatically reduce well productivities, especially for open hole completed horizontal wells. The economic impact of poor productivity of these wells has pushed toward significant efforts in recent years to study laboratory testing techniques and numerical modeling methods for predicting and controlling drilling-induced formation damage. This paper presents an integrated approach, combining a near-wellbore modeling with laboratory experiments for data acquisition as input for the model, to evaluate the performance of oil and gas wells after drilling-induced formation damage.

A fractal model for predicting permeability around perforation tunnels using size distribution of fragmented grains

A methodology to predict the permeability distribution around the perforation tunnels is presented. The resulting equation describes the permeability by modeling the distribution of grain fragments and by fractal concepts. The equation allows the calculation of permeability from the particle size data obtained from the rock material surrounding the tunnel. The fractal model constructs a flow equation for an incompletely fragmented porous media by describing the geometry and size of the pores using the grain size distribution and setting up a hierarchical scaling concept for fragmentation to eliminate the extra porosity of a completely fragmented fractal porous medium. Predicted permeabilities (as compared to measured ones for the 2.4- and 5.1-MPa underbalance shots) using the developed equation showed that the predictions are successful at almost all radial positions around the tunnel. Relative errors between predictions and measurements increase towards the tunnel wall. This may be attributed to the unfavorable particle shapes, which are assumed to be spherical in the model, and aspect ratios of fragmented grains. It also was observed that predictions for higher underbalance test are better due to better surge flow cleaning, which eliminates most of the small particles affecting the calculations due to their unfavorable shapes. The developed equation provides an easier and cheaper way of mapping the permeability distribution around the perforation tunnels compared to the viscous fluid injection and pressure transient measurement techniques. The proposed technique can be valuable to obtain permeability distribution data for near-wellbore modeling of specific formations perforated at laboratory conditions and also for the assessment of the permeability damage created by different charge and gun designs.

Near-Wellbore Modeling To Assist Operation of an Intelligent Multilateral Well

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 71828, "Near-Wellbore Modeling To Assist Operation of an Intelligent Multilateral Well in the Sherwood Formation," by C. Lucas, SPE, Schlumberger; P. Duffy and E. Randall, SPE, BPAmoco; and Y. Jalali, SPE, Schlumberger, originally presented at the 2001 Offshore Europe Conference, Aberdeen, 4-7 September.

On Near-Wellbore Modeling and Real-Time Reservoir Management

Summary This paper is concerned with the problems of real-time reservoir management, simulation while drilling (SIWD), and near-wellbore modeling. These problems are discussed in terms of work process, feasibility, and numerical- and simulation-related aspects. A software tool developed to perform high-precision local simulation while accounting for global field behavior is described. Field examples are presented to illustrate the potential and use for SIWD exercises.