In this research an integrated reservoir study was performed on one of the successful water flood projects in Bapetco; The NE-Abu Gharadig-1 field which passes through a several phases of development started with appraisal and delineation, initial development (fast track), re-development phase and last phase of reservoir simulation. The conducted field re-development activities increase the EOR expectations and tackle the remaining reservoir potential. Until the moment 58 wells were drilled in this field 29 oil producer, 26 water injector and 3 water source wells. Different accumulations and segments were interpreted; these segments did not indicate full communication as the thinly bedded Bahariya sequence of 200 meter thickness shows a wide range of reservoir properties and heterogeneity including porosity, permeability and hydrocarbon saturation. Geo-cellar modeling approach was beneficial in this field in order to link the static and dynamic data until reaching a certain level of match and harmony. Twelve productive zones were interrelated through an attempt to construct structural and stratigraphic facies distribution framework guided by cores and BHI. The 3D geo-cellar modeling was applied to the probable cases and prospective blocks. Petrel data analysis tool was activated in order to control the probability distribution in property modeling. Further reservoir simulator was used to incorporate the engineering data as pressure and production; therefore optimal development strategies are aligned with the findings and forecasts of each reservoir sector. The results indicate a massive variation in vertical and lateral OIIP distribution and URF which is ranging from 16 % to 40 % on the best chances; this variance controlled by the reservoir architecture, compartmentalization, reservoir rock types, relative permeability curves, minor faults and fractures associated with different stress regimes. The WF pattern fitting and placement were optimized to overcome the geological constrains by additional two phases of infill wells. The results provides a robust reserves stair case through a multi-phases of development and modeling to increase the field production life, improve pattern flood, optimize enhanced recovery and smooth operation.

Reservoir quality in terms of Net-to-Gross (NTG) remains one of the critical components in determining the Hydrocarbon-initially-In-Place (HCIIP), recoverable reserves and production rates of any producing field. Often times, fluvial channel and shoreface deposits are credited to have very good reservoir qualities, hence are choice candidates for completions post-drill of the well. In addition, examples exist of heterolithic sands from which considerable reserves have been recovered during the life-cycle production of the Cream Field in the Niger Delta basin, Nigeria. Improved production from these reservoirs is associated with optimization of well designs. Heterolithic deposits are made up of interbedded sand and mud/shale. These deposits are typically laid down in environments like the tide dominated deltaic and estuarine environments as found in the Niger Delta of Nigeria.The Heterolithic sands found in the field to be discussed are mainly lower shoreface sands with lesser transgressive sand units; lower energy, variably sorted sandstones which are typically finely laminated and commonly intensely bioturbated. There is a continuous transition between heterolithic and shoreface sands. Reservoir quality tends to increase upwards as the heterolithic sands grade into shoreface sands.The sands have poor Kv/Kh values due to presence of shale laminates within the sand deposits. This exacerbates the poor sweep efficiency of the oil with high possibility of by-passed oil. The overall impact of these challenges is low recovery factors assigned to the sands.Due to the properties and nature of the heterolithic sands mentioned above, there is usually low pressure support due to poor aquifer connectivity as a result of the depositional environment, thus triggering a depletion drive mechanism.Interestingly, some of these heterolithics hold considerable recoverable volume that makes the exploitation of such reserves important. Such is the case offshore Norway, Alaska, Canada, Venezuela, Russia, Nigeria and indeed world-wide. As a result, production optimization therefore becomes critical to maximize recovery from wells completed on this facie type.The paper reviews the occurrence of this heterolithics in a field in the Niger Delta, the challenges faced with the current completion strategy and the reservoir management practices. A major challenge as observed in conventional crestal completion on the structure is early gas breakthrough from secondary gas cap formation. Methods of enhancing recovery from heterolithics using improved completion strategy and the requisite reservoir management practices are set forth in the body of the paper.Completion strategies like horizontal wells targeted at the good quality sands has shown an additional potential 1300bopd (seen in the performance of the only horizontal well in the field) as compared to performance of conventional wells, simulation study of water injection and gaslift has also indicated an increase in reserves by 10MMstb.

The importance of Wells, Reservoir, and Facility Management in the life of producing Oil and Gas assets cannot be overemphasized. Several authors in the past have highlighted the significant contributions WRFM practice and process have to the ultimate recovery of matured assets. WRFM serves as a stop-gap to redevelopment in areas of cash crunch, whereby active WRFM practice arrests severe natural decline in production. Onshore assets comprising of fields Alpha and Beta are operated by Shell Petroleum Development Company (SPDC). These assets have been operated for over 30 years, rising water cut & high gas-oil ratio production and facility downtime risks have impacted oil recovery. This work showcases the application of WRFM at the re-startup of production in these fields post shut-in for almost 5 years. Effective and deliberate application WRFM processes and practices woven together in the WRFM Plan not only ensure an efficient restart of the facility but the ability to ramp production while maintaining the intricate balance of good reservoir management. The paper will highlight the best WRFM practices which enabled the resumption of production at a lower water rate compared to when the field was shut and maintain this higher net oil for a prolonged time. Also highlighted are opportunity identification and implementation in-closed wells and effective collaboration across disciplines to ensure a safe and efficient restart of production facilities.

This work demonstrates the usefulness of data quality checks for the purpose of achieving test objectives with an example from a Niger Delta well. The well UGO-1X was completed as single-zone single string (SSS) configuration with a 4-1/2 inch, 12.75 ppf, 13Cr HCS production tubing. The well was tested in order to characterize the reservoir, determine the completion efficiency and ascertain reservoir limit for GIIP estimation. The test program involved multirate production, followed by a build-up phase for which a Down-Hole-Shut-In-Tool (DHSIT) was deployed to manage wellbore storage effects. However with the conclusion of the multirate test, and commencement of build up, the downhole shut in tool (DHSIT) failed and subsequently the well was shut-in at the surface and the build up (BU) stage allowed to progress as per programme.Following the conclusion of UGO-1X multi-rate test (MRT drawdown and build up), the data was retrieved from the quartz gauges, quality checked and analysed using the conventional and numerical simulation methods. This paper illustrates the difficulty of interpreting an incomplete set of data, the importance of properly understanding the operational history in well test analysis as well as the usefulness of conducting a quick analysis to validate data thereby avoiding a repeat operation. It is shown that by careful reprocessing of the data (de-listing data within the DHSIT failure interval), the overall quality of the data could be significantly improved and used to produce credible results. This made it unnecessary to conduct a repeat of the MRT/BU on UGO-1X as initial test objectives were achieved.

Often, the production of oil and gas from underground reservoirs is accompanied by produced water which generally increases with time for a matured field, attributable to natural water encroachment, bottom water ingress, coning effect due to higher production rates, channeling effects, etc. This trend poses a production challenge with respect to increased OPEX cost and environmental considerations of treatment/handling and disposal of the produced water considering the late life performance characterized by low reward margins. Hence, produced water management solutions that reduce OPEX cost is key to extending the field life whilst ensuring a positive cash flow for the asset. SK field is located in the Swamp Area of the Niger Delta, with a capacity of 1.1Bcf gas plant supplying gas to a nearby LNG plant. Oil and gas production from the field is evacuated via the liquid and gas trunk lines respectively. Due to the incessant tampering with oil delivery lines and environmental impact of spillage, the condensate is spiked through the gas trunk line to the LNG plant. Largely, the water/effluent contained in the tank is evacuated through the liquid line. Based on the availability of the liquid line (ca. 40%-60%), the produced water is a constraint to gas production with estimated tank endurance time (ca. 8 days at 500MMscfd). This leads to creaming of gas production and indeed gas deferments due to produced water management, making it difficult to meet the contractual supply obligation to the LNG plant. An interim solution adopted was to barge the produced water to the oil and gas export terminal, with an associated OPEX cost of ca. US$2Mln/month. Upon further review of an alternate barging option, this option was considered too expensive, inefficient and unsustainable with inherent HSSE exposure. Therefore, a produced water re-injection project was scoped and executed as a viable alternative to produced water management. This option was supported by the Regulators as a preferred option for produced water management for the industry.