Exceeding the estimated technical UR of mature fields is a valid positive risk to be considered in field development. Extending the field life of prolific fields in the Niger Delta using integrated subsurface analysis of available data is an imperative in the current "lower price for longer" oil economy. For matured reservoirs producing beyond their estimated ultimate recovery, it is necessary to demonstrate the basis on which a revision of recovery factors can be made (SPE et al., 2007). This paper examines how the seismic, geological, production data and pressure data were integrated to arrive at the most plausible reservoir understanding for the re-allocation of In-place volumes for the Tanure field in the Western Niger Delta. An integrated review of the field history was done on a well- by- well basis, taking into account the cross -sections and relative positions of both flowing and closed -in wells. The CO log data analysis showed the relative movement of the water influx in the field, helping to identify wells that had been shielded by sealing faults, explaining observed production performance. The pressure equivalence of the hitherto separate sub-blocks in the field proved that 75 of the sub-blocks on the various reservoir sand levels could be technically merged into 24 larger blocks. The average contacts for the new sub-blocks were estimated by petrophysical analysis of original contacts observed from open hole log data. The re-interpretation of 3D seismic and the fault model of the geological structure, led to the revision of Stock Tank Oil Initially In Place (STOIIP) estimates to support the production figures from the maturing field (SPE/WPC, 2001). Fluid contact analysis estimated OWCs for the resulting new blocks, confirmed by pressure data history from the field. The technical recovery limits for the affected blocks were revised based on the calculated STOIIP volumes of the new blocks.
The use of dynamic method to determine hydrocarbon in-place volumes in R5000 reservoir in Urad field became necessary when it was discovered that the in-place volumes estimated in previous studies for this reservoir cannot be validated by current production data. A combination of Buckley Leverett and Decline Curve Analysis has been used to significantly reduce the wide range of uncertainty reflected in previous in place volumes estimation. R5000 reservoir in Urad field has two producing wells, one closed-in well and two planned wells; from production data review, it was discovered that estimated in-place volumes was less than optimum. The challenge of re-evaluation to obtain result that both structural interpretation and production performance data will support arose. This paper therefore has deployed Buckley Leverett method with assumption of moderate water drive and gravity drainage to approximate a water flood and as such predict recovery efficiency using the interaction between fluid mobilities, fractional flow and water saturation. Decline curve analysis performed on the producing wells in R5000 reservoir was used to derive technical Ultimate Recovery and a reverse calculation has been done to estimate hydrocarbon initially in-place that supports structure and production data. The recovery factors of three reservoirs in Urad field, namely P1000, H2000 and K3000 have been previously estimated in an earlier study on this field using Buckley Leverett method and result obtained in this work was validated by repeating the BL evaluation for these three reservoirs to reproduce the recovery factor results obtained in earlier study. This work provides a solution to the challenge of estimating hydrocarbon initially in-place volumes in reservoirs where available rock and fluid data as well as fluid contacts information are not reliable.
Coalbed methane (CBM) holds promise of relatively clean, stable natural gas supply in the emerging global energy map. This project summarizes the integrated modeling of a unit of a coalbed methane reservoir-well-surface facilities system. The pro ect demonstrates the resulting reservoir and system response for different well fluid and pressure conditions, for a range of artificial lift parameter and surface facilities constraints. An economic cost model is also linked to the coupled system, which incorporates ranges for gas prices, water handling costs, capital and operating costs and discount rates. The instant capability to examine the possible net present values and internal rates of return for a given production stream of gas and water is also demonstrated. The simultaneous optimization of the reservoir, well, surface and economic models in a single simulation run made possible by proprietary oil industry software enables the observation of the system behaviour instead of just the reservoir as has been mostly done in industry. The reservoir effects on this coupled system are presented to explain important considerations in CBM feasibility considerations. The resulting model is scalable to deal with larger fields and well patterns.
The impact of intra-reservoir faults on fluid connectivity and recoverable volumes in any reservoir depends principally on structural uncertainties (fault extent, fault throws, fault zone, fault heave, fault sealing capacities etc.) associated with the reservoir. This paper focuses on the integrated approaches used to determine block by block fluid connectivity, re-assignment of estimated hydrocarbon initially in-place volume and its associated recoverable volumes in different reservoir blocks in view of production performance and complex fault architecture in the field. In this study, we have explored the feasibility of determining fluid connectivity across reservoir blocks and their associated recoverable volumes by integrating reservoir performance (post-production data) with the reservoir structural uncertainties. Over 50 wells have been drilled in the field and their penetrations spread across the reservoirs. Pressure data were acquired across most of the blocks in the reservoir. The reservoir is sub-divided into separate blocks and it has over 25 years of production with evidence of over-production (Np > Ultimate Recoveries) experienced in some of these blocks. This over-production triggered the need to integrate available data (Performance, Pressure data, Fluid Contacts, structural morphology etc.) to re-evaluate the impact of the intra reservoir faults on the estimation of the hydrocarbon in-place volume and recovery in the field. The integrated approach has aided the re-estimation and re-assignment of the associated volumes on a block by block basis thereby promoting the opportunity for a robust infill well planning and further development of the field.
The productivity of oil wells depends on a lot factors such as and not limited to environment of deposition, reservoir thickness, permeability, reservoir drive mechanism, drain hole length and formation damage at the near well bore region. The productivity of oil wells can also be linked to the effectiveness of the sand control method deployed in the well. Sand control methods play very important roles in safeguarding our assets, maximizing production from assets and reducing life-cycle OPEX for the well. This paper presents a comparative approach towards understanding the effect of different sand control methods on productivity of wells completed in a mature reservoir in the Niger Delta. The methodology involves the use of statistical comparison of the production performance of 4 sand control methods installed in the XYZ reservoir in the YED field. The approach considers the productivity performance, the average sand reliability index, and the intervention frequency ratio. The productivity performance of the completed conduits on XYZ reservoir shows that conduits completed with Slotted Liners showed impressive production performance as well as low sand production, while the wells completed with IGP had better production performance when compared to other sand exclusion methods. The drainage points completed with SCON showed average production performance, with high sand production averaging around 25-30 pptb for the completed conduits. The conduits that were completed with MCUGP showed below average production performance as well as high sand production. The results in this work will help provide an easy guide to sand control selection as it concerns productivity in the Niger-Delta region. It will also deepen the understanding of the performance of different sand control methods in the Niger-Delta Region.
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