Advanced hydraulic fracturing has become a complex and investment intensive operation; hence, predicting its performance has become more important than ever. Robust prediction of production profiles for hydraulically fractured wells is imperative for optimizing the fracture scheme for productivity and determining completion economics. Various methods are currently being applied to modeling production after hydraulic fracturing treatments ranging from traditional analytical methods to semi-analytical and advanced numerical methods. A key requirement for any production modeling approach is the ability and flexibility to cope with uncertainty in fracture, reservoir and well properties to optimize fracture design. In this study, we applied different modeling techniques to a range of fracture treatment scenarios and compared several real case studies and examples from the North Sea area. A number of factors had to be taken into account during the selection of a particular production modeling technique. These factors included considerations related to well type, fracture design, extent of geological and petrophysical properties, availability of data and ready reservoir models, and turnaround time. Multiple simulations generating multiple production profiles were carried out in most of the cases to support uncertainty bracketing and guide informed decision making even in areas extending to completions optimization. The results reflect the need to curtail the use of simplified models and approaches when sufficient data is available or where data can be integrated to further reduce uncertainties on a case-by-case basis. On one hand, hydraulic fracturing treatment can be capital intensive while on the other hand, profitability is often a dynamic and changing parameter. Hence, longer term productivity benefits (post fracturing) require explicit and realistic pre-evaluation. Finally, the work highlights robust approaches for uncertainty handling within the production modeling workflow.

The formation of near well-bore scale can have detrimental impact on well production. Pore plugging, restriction in wellbore i.d. and perforation plugging due to scale deposition can sometimes remain undetected over prolonged periods especially when very low water production is evident. To overcome this uncertainty, workers in our industry usually rely solely on scale prediction models to identify the potential of scale occurring. However, rarely is this information utilized further to explicitly quantify the impact of scale deposition on well performance and updated in the reservoir model, allowing better field management to be applied.In general, historical work published on scale prediction analyses have concentrated on identifying the potential of scale formation based on water composition(s) and localized information such as pressure, temperature (thermodynamic), while more recent publications have attempted to capture the kinetics and fluid hydrodynamics involved.Whilst these predictions can be very useful, it remains a challenge to then use the data output to quantify the impact of scale on overall well performance explicitly. Additionally, limiting factors and uncertainties can exacerbate the problem further. Examples are:• Availability of multidisciplinary tools to capture the processes involved • Uncertainty in field data including hydraulic flow units • Uncertainty over which layers bear 'scaling water' • Presence of multiple source of formation damage (e.g. fines migration) • Presence of other factors that can impact well performance (e.g. liquid loading, lifting) • Near-wellbore / formation scaling need not be seen physically This paper presents an overview of a new simulation workflow development to capture the impact of scale formation by coupling the domains of chemistry and reservoir engineering. Reservoir, near wellbore and macro-scale simulation techniques were integrated to evaluate the impact of scale deposition on well performance during the production lifetime.From the concise simulation workflow developed, we show how scale has impacted production in two synthetic wells, and more importantly, to characterize the location of the depositing scale. Initial problems relating to uncertainties in flow unit description and identification of potential layers of water source are highlighted, and the solutions to overcome these uncertainties are discussed. Based on this information, the volume of scale deposited at specific locations are enumerated and converted to wellbore and formation skins. Over time, slow deposition of scale was shown to clog up sections of specific perforation intervals along the well length and near wellbore area. By reverse engineering, the explicit impact of scale deposition on well production over time was quantified.

Reservoirs in the Niger Delta oil province are predominantly weak sandstones and unconsolidated sands of the Agbada formation. Wells in these reservoirs are susceptible to sand production as production entails high water cut. Sand production is triggered by mechanical failure near the wellbore and occurs when the near-well deformation process changes. The deformation process is controlled by parameters such as production rate, drawdown, reservoir pressure changes and reservoir formation properties. Mechanical failure of the reservoir leads to the mobilisation of failed material and changes the near wellbore porosity and permeability of the rock.The Chestnut Field operated by Centrica Energy and partners (block 22/2a, Central North Sea, UK sector) has been under production since 2008 despite continuous sand production. The reservoir consists of unconsolidated sand with a porosity average above 30% and permeability of 0.5 to 2 Darcy similar to many Niger Delta sand reservoirs. This paper introduces the Sand Production and Pore Pressure Management Program which was implemented to control sand production and maintain hydrocarbon production. Additionally, an analysis of near wellbore porosity and permeability changes is presented.Real-time data acquired from four wells over a period of more than four years and the production of over 140 tons of sand were utilised. The results indicate a change in porosity and permeability which is consistent with a change from compaction to dilatancy conditions near the wellbore. These changes have had a significant impact on the sand management strategy implemented to optimise the production through the field life to date.

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