Infill opportunity identification in a mature reservoir has some unique challenges because of the uncertainties in exact fluid front movement. These uncertainties are magnified for waterflood or gas-flood reservoirs. The reservoir of interest is a saturated oil reservoir with 54 years of production history and under waterflood. The aim of this study was to validate with a dynamic simulation model, infill opportunities proposed from using a combination of map-based assessment and current reservoir production data. High-resolution reservoir characterization was done to properly capture the different stratigraphic units in the reservoir. Insights from production and pressure behavior formed part of the input during the characterization phase. Results of the characterization step were used for earth modelling to generate a base case earth model for the reservoir used for history matching. Pro-cycling of the model was done during the history matching process, enabling the narrowing of fluid-in-place uncertainties during history matching. This resulted in a high-quality history-matched model that replicated over 80 percent of the fluid contact movement observed over the production life of the reservoir. This model was then utilized to validate two proposed infill opportunities in the reservoir. A key lesson identified during the process is that the use of high-resolution reservoir characterization methods prior to the earth modelling stage ensures better tracking of fluid-front movement and better replicates observed historical data. Rapid cycling between the earth modeler and simulation engineer also delivers significant value, by helping to resolve history-matching challenges early on and ensuring alignment between the dynamic model and the static interpretation of the reservoir.
In the Early phases of field development, the drilled hydrocarbon appraisal wells may not have been sufficient to define rock properties, fluid typing and contacts. It's very important to define the range of uncertainty in such fields. This is because as the field matures other dynamic data will become available to validate these probable volumes. The ideal development scenario provides the practitioner with a full suite of data defining the reservoir geometries, reservoir properties, fluid properties etc. to make subsurface decisions. However, in most cases, operational realities will deny the reservoir practitioner this full suite of data. One practical convention that is used to resolve this data paucity challenge is to evaluate and report the lowest possible volume, if this low case is economic the project will be economic with potential for more upside outcomes. However, a challenge that can arise with this is that after several iterations the low case can become the only case. A better practice is to characterize uncertainty of reservoir parameters during the early stages of field development and carry out the full range outcomes through the field's life. These ranges will then be validated as the field matures. This paper demonstrates a case in the Niger Delta field A05 reservoir were dynamic simulation model was used to narrow the uncertainty range on the GOC. Proper identification and characterization of the GOC uncertainties helped for the estimate of a range of STOOIP used for dynamic simulation model. Though no static dataset was available to reduce this uncertainty on the GOC, during dynamic simulation, the high-case oil in-place volume was found to be the best match to historical production data with the integration of another reservoir, Delta A12, in one dynamic simulation model. Both reservoirs communicate through the aquifer, separated by a saddle. This then proved up additional volumes in the reservoir, identified previously overlooked reserves and allowed the asset team to propose an extra infill well opportunity than what was previously planned. This new understanding of the A05 reservoir increased the oil estimated ultimate recovery (EUR) by 4.6 MMSTBO.
The objective of this paper is to share lessons from an intensive study of a mature reservoir and highlight its results. This study also aims to demonstrate the value that can be obtained from a mature conventional oil reservoir when the appropriate assessment processes are utilized. The case study is an offshore oil reservoir with over 50 years of production with waterflooding for almost a decade. The dynamic simulation model from an earlier assessment of the reservoir showed significant deviation following years of waterflooding, as it became more challenging to understand the water front movement, predict water cut changes and deliver more reliable liquid production forecasts. The reservoir had historical challenges with water production and matching the water-cut from producing wells emphasizing the deviation of the existing simulation model from actual data. As a result, a cold-eye review of all available data without anchoring on prior interpretations was required. An updated reservoir characterization and earth modelling methodology was applied during the study with attendant improvements in structural and stratigraphic representation of the reservoir. A full-field assessment methodology was employed in the study both for the fault framework and model building, ensuring the inter-reservoir connections and dependencies were captured. Additional scrutiny was applied to initial fluid contacts, leading to the resolution of longstanding uncertainties. This resulted in the delivery of a new dynamic simulation model with a much better water cut history match compared to the previous study. Fluid contact tracking over time was also better matched using the new model. The new model indicated an increase in original oil in place of 38% leading to the identification of 2 new infill producer opportunities with total estimated ultimate recovery of several millions of oil barrels.
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