A multi-tank model is presented that was used to evaluate the volume of gas produced from an undeveloped gas reservoir as a result of sand-to-sand juxtaposition with a developed oil rim reservoir. An innovative approach of using Microsoft Excel via OpenServer to link MBAL model to history match reservoir pressures in a multi-tank model, while considering all the reservoir uncertainties was adopted. The process helps to save time in Reservoir Management. An oil rim reservoir with future gas development seemed to be communicating with an undeveloped gas reservoir via sand to sand juxtaposition based on the pressure data taken during the drilling of one of the wells and fault seal analysis. This clearly showed depletion in the undeveloped gas reservoir. Through a multidisciplinary approach, the two reservoirs were built into tank models and connected using a transmissibility model. The resultant model was history matched using an experimental design approach and contacts calibrated prior to running simulation and prediction. The result showed the quantity of Gas Initially in Place (GIIP) in the undeveloped reservoir that has flowed into the developed reservoir and has possibly been produced already. This insight provides a quick analytical understanding on the resource volume impact of this phenomenon on both reservoirs with respect to their future gas development. This has led to the need for a revised development plan for both reservoirs with respect to future gas production. The novelty of the use of experimental design with MBAL multi-tank model in this scenario is in the ability to history match the model in reasonable time. This is achieved while effectively managing reservoir uncertainties. This is critical for key business decisions on reserves booking, business planning, general reservoir management and production.

A quick evaluation of reserves for new opportunities (e.g. perforation extension and other work over types) in reservoirs with distinct geological units and features is possible using a multi tank MBAL option. This saves time while still having results closely matching more detailed simulation models besides reservoir management due to subsurface uncertainties. In cases where a reservoir is naturally separated into units with the aquifer as the only common communication base or where there are constricting saddles which in production time allows preferential sweeping of the reservoir posits the possibility of separate tanks. Multi-tank MBAL has been used in this scenario to generate a production forecast for a work over opportunity in Reservoirs A, B & C. This methodology transmits the segregated accumulations of the reservoirs into tank sectors and connects them using transmissibility value to a common aquifer leg in a multidisciplinary approach. Resultant model is history matched and contacts calibrated prior to prediction especially when present contact information exists. The methodology as opposed to a single tank MBAL model gives better calibration of contact movement and forecast of the future and existing opportunities, thus giving credence to more robust reservoir management plan and resource volume estimation for the work over project. The MBAL multi tank methodology is a handy improvement tool for brownfield production forecast within the Wells, Reservoir & Facility Management domain especially where no 3D dynamic models exist.

Sustained Annulus Pressure (SAP) is a common production constraint in the oil and gas industry, it is usually caused by impaired seal Integrity within the wellbore system resulting in barrier failures. In peculiar scenarios the thermal expansion creates pressure build-up in the annulus as well which can equally impair the integrity of the wellbore. In this paper the results of downhole and surface pressure monitoring surveys are presented, the objectives aim at determination of both downhole leaks and verification the influence of thermal expansion into a wellbore system integrity in a field located onshore Niger Delta. SAP in a producing well was earlier recorded during routine annular pressure monitoring in 2017 during the production rate increase by changing the bean size from 18/64" to 24/64". Initial diagnostics observed pointed towards SAP resulting from a possible downhole seal integrity issue leading to a leak to the surface. While putting the well on stream with current bean size and the pressure regime for both THP and CHP was observed. Pressure with time analysis showed annulus pressure builds up rapidly while flowing and bleeds off within 30 min from 700 psi to 0 psi when well shut in. Downhole logging and sensitive passive acoustic monitoring was conducted, the survey aimed to detect barrier failures by capturing its acoustic leak patterns under shut-in and bleeding off condition. Considering the suspected leak behaviour, the data acquisition included the procedure to build up the annulus pressure by flowing the well and monitoring the annulus discharge. Integrity logs survey and passive acoustic monitoring confirmed there were no downhole failures and after several bleed-offs when Tubing choke was beaned down to 18/64" no annulus pressure build-up was observed from the Well head gauge on the Casing head confirming the source of the sustained annulus pressure is driven by the temperature expansion of the annulus fluid. Remedial action and recommendation after Simulation were to de-risk the well at a controlled bean size to mitigate SAP and optimally flow the well.

Uncertainty management for resource volume of a brown field is relevant. An analytical approach via dynamic model was used to evaluate this impact on a developed gas reservoir (brown) by two other reservoirs. One of them is a green oil-rim reservoir, while the other is a developed oil reservoir. This is due to sand-to-sand juxtaposition with the two reservoirs. Integration of available data over time, while considering all the reservoir uncertainties was adopted. This was buttressed by the continuous production from the gas reservoir, that had already gone past the initially evaluated Gas Initially in Place (GIIP). The brown reservoir is a highly faulted gas reservoir with twenty-seven (27) years production history, by seven wells. The reservoir's GIIP re-evaluation had been done twice over the years. This was because it had fully developed its ultimate recovery, with three wells still producing. This GIIP re-evaluation approach could no longer be utilized, as it had very good well coverage. Fault seal analysis, pressure, PVT sample and log data taken over time reveal the likelihood of communication across the stacked reservoirs. A multi-tank material balance model (MBAL) was built via a multidisciplinary approach. The model was history matched using an experimental design approach that saved time and contacts were calibrated. The result showed the quantity of hydrocarbon in both reservoirs that have flowed into the developed gas reservoir. This provides a snapshot on the resource volume impact of the reservoirs with respect to their development and uncertainty management. Revised development plans and resource booking for the reservoirs are also study outcomes. This is relevant for business decisions on resource volume booking and reservoir management. This approach is a quick win within the Well, Reservoir and Facility Management (WRFM) workspace. Further work by building a 3D simulation model and pressure data acquisition is required for robust benchmarking.

Beta Integrated Oil and Gas plant is the major supplier of domestic gas to the Lima power plant which provides 16% of the available power to the Nigerian national grid. Efforts are made to ensure that down times in the plant are reduced because of the huge impact to domestic gas supply in the country. Between 2014 and 2015, multiple tripping had been observed on the transfer pump at the Beta gas plant. Laboratory analysis of the recovered solid deposits in addition to scale simulations of the hydrocarbon fluid confirmed the presence of calcium carbonate scale (85.2%wt). Although the culprit well was identified, a cost-effective surface chemical solution was immediately deployed upstream of the facility which significantly reduced the export pump downtime due to scaling and clogging. The overall treatment option adequately mitigated the calcium carbonate scale observed and also led to significant savings in pump maintenance of about a million dollars. This paper will be discussing the problem and underlying restrictions faced by the multidisciplinary team, problem solving approaches considered as well as the solution employed by deploying Phosphate Ester based chemical scale inhibitor. The scale inhibitor is specially formulated to prevent the formation of calcium carbonate, calcium sulphate, barium sulphate and strontium sulphate scales in producing wells, water injection systems and saltwater disposal systems. One major consideration in the choice and use of the product is the cost effectiveness of the product, its potency and suitability at effectively mitigating the calcium carbonate scaling in the gas plant. It was successfully qualified in the lab for use with MIC of 10-20ppm and has been previously deployed in our deep water facility. Laboratory tests indicate it is effective in produced water with iron and high bicarbonate content as is the case for Beta gas plant. In addition, laboratory tests indicate it does not encourage deposition of naphthenates in produced water as is observed with some phosphate based scale inhibitors. The product is also readily available in-country hence no long delivery lead time challenges, besides there is significant cost and logistics value to be realized from its deployment in Beta oil and gas plant.