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.

Thermally induced fractures, TIFs, occur in almost every water injection well. They are the result of the cooling of the reservoir rock as water reaches the sand face and near wellbore area. This cooling generates a contraction in the rock that results in a change in reservoir mechanical properties and the near wellbore stress conditions. The importance of understanding and engineering the process of TIFs is quite often underestimated, as TIFs are assumed to happen as under normal injection conditions. However, how TIFs are generated has a large impact on areas such as casing and reservoir isolation, well integrity, injectivity profile and eventually pressure support or water disposal strategies. This paper presents the results of technical and field efforts carried out to overcome a variety of problems in water injection wells in two (2) particular types of reservoir: a high permeability (> 0.8 Darcy) and a very low permeability (< 0.03 Darcy); both sandstones located in the North Sea. Work was carried out in four(4) wells to utilize TIFs as a tool to maximize water injection and minimize well and reservoir integrity issues. This paper presents in detail the design process, its operational implementation and the results obtained for each reservoir. In both types of reservoirs, TIFs has allowed us to restore long term injectivity by overcoming a large number of constraints such as high levels of formation damage, varying formation strength for different type sand face completion design (open hole and cased/perforated) and well configurations. We also describe the science and details of the operational characteristics, results and evaluation methods used to restore or improve water injection. We conclude that TIFs plays an important role in water injection wells and can be used, among other things, to initiate injectivity, overcome high injection pressures, minimize well integrity issues and fulfil its main objective (maximum injectivity). TIFs can therefore have a significant economic impact and limit the effect of impaired injectivity over time.

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