Computational Fluid Dynamics (CFD) has been used to model fluid behaviour in reservoirs, near wellbores and wells. More recently the CFD has been applied to more diverse challenges such as sand transport, coupled mechanical modelling of failing wellbores and gas well clean-up. CFD has been applied to model the crushed zone around perforation tunnels and also to predict well performance base on laboratory testing. Where the reservoir is involved in these models they are fully coupled and flow is enabled deep in the reservoir and in to every point along the well. Capturing the simultaneous flow of fluids in the reservoir and in the well is essential to predict performance in wells and reservoirs with complex geometry. Cross flow between reservoir layers and the flow of fluids through and along the well length are real phenomena which if ignored, can lead to poor prediction of well performance. CFD modelling relies on fundamental physical properties and enables changes in flow restriction such as formation damage or matrix stimulation to be captured. This paper presents some recent case histories where model results are verified by real well performance and where traditional analytical model results are compared to fully coupled CFD reservoir and well models. The impact of formation damage is observed to produce very different results, depending on the model applied. Case histories illustrating the application of innovative, rigorous modelling of formation damage from different drilling and completion fluids and practices are presented. Further advances that enable sand failure and sand transport to be modelled are also illustrated. The case is made for use of CFD or similar modelling processes where complex reservoirs or complex wells are considered. IntroductionCFD has well tried and tested applications in many industries including the oil and gas industry. Here it has principally been used to model fluid flow in surface pipelines and to examine fluid flow through and around tubing and equipment. For example CFD is used in the design and development of new drill bits and in the development of Inflow Control Devices (ICDs). More recently there has been an increasing trend to move CFD in to the well and the complexity of completion and reservoir geometries (Byrne et al 2010). This evolution has been enabled by the advance in computational power and speed and by improvements in CFD software packages. CFD enables modeling of the physics of fluid flow through restrictive media and so is ideally suited to modeling the flow of fluid or fluids through reservoirs, completions and wells. Previous papers have presented some of the earliest work in this field but even in a few short years significant progress in the accuracy and the scale of modeling has been made. Complex phenomena such as unloading liquid completion fluid from gas wells, sand failure and the impact of changing wellbore shape on fluid flow and complex well geometries have now been modeled and used to assist in the design of optimum wells. A case study is pr...

The drilling of wells offshore West Madura, East Java, can be challenging. The geological structure of the area often requires drilling at high deviations with large stepouts, through formations consisting of carbonates, shales and sands. As a result, wellbore stability issues are frequently encountered, such as total mud losses, stuck pipe, loss of bottom hole assemblies and associated sidetracking, leading to non-productive drilling time and unnecessary costs. In order to lower the associated risks the operator commissioned a geomechanics study, to identify the root causes of the wellbore stability issues, and provide recommendations for improved drilling of future development wells. Numerous wells had been drilled within the area of interest over more than three decades, resulting in a large variation in the availability and quality of data. Recently acquired 3D seismic data were also available. Therefore, a multidisciplinary approach was employed with geomechanics at its core, accompanied by well log conditioning, generation of synthesized shear sonic logs, simultaneous seismic inversion, and drilling engineering. The integration of the different disciplines ensured the development of robust 1D and 3D geomechanical models, which were applied to develop mud weight recommendations for the planned development wells. Firstly, a 1D geomechanical model was constructed. Two recently drilled wells had excellent data sets: extended leakoff and minifrac test results showed very consistent fracture closure pressures. This, combined with the presence of borehole breakouts and direct rock strength measurements on core, allowed the determination of the minimum and maximum horizontal stresses with only small ranges of uncertainty. The 1D geomechanical model was further calibrated by a detailed comparison with critically reviewed drilling incidents. Simultaneously, well logs were conditioned and pseudologs were created, which were used for 3D simultaneous seismic inversion, from which rock property volumes (P-impedance, S-impedance, and Vp/Vs) were derived in turn. Gardner’s relationship was used to transform the seismic velocity data to a density volume. The 1D geomechanical model was subsequently combined with the 3D seismic data via a structural model grid, resulting in a full 3D geomechanical model containing cubes of pore pressure, principal insitu stresses, elastic rock properties and rock strength. Finally, wellbore stability analyses were performed for the planned development wells, including a quantitative risk assessment to gauge the impact of uncertainties in various key variables on the overall potential drilling success. Well deviation and azimuth sometimes showed a counterintuitive effect on recommended mud weights, as illustrated by stereonet plots. A key factor in the execution of this project was the integration of data and expertise in petrophysics, seismic inversion, geomechanics and drilling engineering over a relatively short timeframe to deliver a technically robust set of mud weight windows, which, combined with recommendations based on a detailed review of passed drilling practices, should enable the successful drilling of the wells in this very challenging environment.

In the United Kingdom Continental Shelf (UKCS), a significant heavy oil prize of 9 billion barrels has been previously identified, but not fully developed. In the shallow unconsolidated Eocene reservoirs of Quads3 and 9, just under 3 billion barrels lie in the discovered, but undeveloped fields, of Bentley and Bressay. Discovered in the 1970s, they remain undeveloped due to the various technology challenges associated with heavy oil offshore and the presence of a basal aquifer. The Eocene reservoirs represent significant challenges to recovery due to the unconsolidated nature of the hydrocarbon bearing layers. The traditional view has been that such a nature represents a risk to successful recovery due to sand mobility; reservoir and near wellbore compaction; wormhole formation; and injectivity issues. We propose improving the ultimate oil recovery by a combination of aquifer water production and compaction drive. By interpreting public domain data from well logs, the range of geomechanical properties of Eocene sands have been determined. A novel approach to producing the heavy oil unconsolidated reservoirs of the UKCS is proposed by producing the aquifer via dedicated water producers situated close to the oil-water contact. The location was determined by sensitivity analysis of water producer location and production rates. By locating water producers at the OWC with a production rate of 20,000 bbls/day of fluids, the incremental recovery at the end of simulation is increased by 4.1% OOIP of the total modelrelative to the ‘no aquifer production’, casesuggesting a significant increase in recovery can be achieved by producing the aquifer. A rate of 30,000 bbld/day located at the OWC was found to increase incremental recovery by 5.8 %OOIP relative to the ‘no aquifer case’. In all cases, as the reservoir fluid pressure is reduced, oil recovery increases via compaction and reduced water influx into the oil leg. This reduced pressure leads to a higher tendency towards reservoir compaction which is expressed as a change in mean effective stress and porosity reduction.

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This paper will describe a workflow undertaken to address potential risks highlighted by a review of a well abandonment plan. The specific issue is described by the potential for failure of a secondary abandonment plug, should the primary plug set relatively deeper had failed. In the case of these events, pressures were sufficient to generate a risk of uncontrolled fracture propagation at the second plug. The initial high fracturing risk was evaluated based on a simple comparison of fracture pressure vs. reservoir pressure column analysis; e.g. the reservoir would deliver a pressure greater than the original fracture pressure at the second and shallower plug depth. To better evaluate the real fracture behaviour and the risk associated with failure of the first plug, a more comprehensive approach was deemed necessary. The main objective of the more detailed study was to investigate the likelihood of fracture initiation, the associated height growth and containment within immediate plug depth formation and overburden. This would be based on the charging pressure and flow volume from the reservoir zone into the plug depth formation. A comprehensive coupled reservoir-geomechanics-fracturing numerical approach was adopted. This included a dynamic fracturing calculation using a non-linear Barton-Bandis material model embedded in a coupled finite-element geomechanical and a multiphase thermal finite-difference flow simulator. In the coupled solution, the fracture propagation is controlled by the nonlinear fracture stiffness and the normal effective stress. The fracture permeability is a function of the fracture width resulting from the poroelastic stress-strain coupled calculations triggered by the reservoir inflow pressure. The modelling results have shown that when a simple low shale permeability was assumed for the second plug and overburden formations, a fracture will rapidly develop vertically up to seabed due to the lower stresses at shallower depths in this low leakoff scenario. However, it was noted that the worst case scenario (uncontrolled fracture growth) was for minimal permeable intervals up to the seabed. In reality the geology using more realistic lithological data showed that overburden has several permeable zones. Accounting for these intervals in the coupled model, the same fracture growth through tight zones was seen, but the growing fracture became vertically contained when reached the permeable intervals. A permeable layer acts as a pressure sink and causes the propagating fracture to lose the energy required for further vertical growth. Sensitivities with overburden permeability, thickness and the estimated reservoir volume were performed. These illustrated that the fracture lateral extension below the overburden permeable sand is largest when the sand permeability and thickness are smaller in magnitudes, and that permeability is the dominant factor. The modelling analysis served to de-risk the likely fracture propagation and containment in an abandoned well in the hypothetical case were failure of the first plug exposes high pressure at a second plug. Even if such failure occurs, it will be a safer (and more cost-effective) alternative, to leave the second plug as its current depth rather than to perform a well re-entry to remove and set it deeper.