In a new field development, enormous time and energy are put in to identify and quantify both static and dynamic reservoir uncertainties. This could be very challenging when information is limited and not readily available. These data uncertainties vary from project to project depending on the quantity of reliable reservoir data acquired during the exploration and appraisal stage. The first step towards managing reservoir uncertainty in field development is to identify and quantify the key reservoir parameters that affect hydrocarbon in place and recovery. These parameters or factors are so many that their combinational effects result in multiple cases of development options, which will require many simulation runs. Stochastic and statistical data analysis coupled with Experimental Design(ED) have been used in recent times to reduce time and energy expended in managing key reservoir uncertainty parameters. The case study presented in this paper gives an illustration of a successful ED application in a new gas field development. A detailed workflow was created to identify and quantify the uncertainties and risks in the dynamic model using probabilistic approach. This resulted in Probabilistic field forecasts that were further used to test surface development options in order to determine the optimal field development strategy that is robust to multiple realisations of reservoir uncertainties
Low oil price and increased environmental regulations presents a new frontier for many indigenous oil and gas companies in Nigeria. In mature fields with significant water production, produced water treatment and handling could easily account for up to a third of OPEX. Underground produced water disposal is a tested approach that has been used worldwide with mixed results. Studies have been published on the subject; however, it was observed that there were no Niger Delta case studies. This paper presents SEPLAT's subsurface approach to in-field water disposal, drawing upon geological and petroleum engineering analysis coupled with learnings from over 6 years of produced water re-injection experience. Some of the areas that will be discussed include reservoir selection/screening methodology, water quality impact on permeability, produced water disposal well selection/completion, operating philosophy, general surveillance, and basic separation requirements. Thirteen reservoirs located within 2 proximal fields were screened for suitability and ranked as possible candidates for water disposal based on 8 criteria. The best 2 were then high-graded and detailed studies carried out, spanning detailed geological characterization for reservoir quality and connectivity (including quantitative interpretation), to dynamic simulation, injection well location optimization and performance prediction (for clean water). The results of core flood tests were incorporated. It is recommended that total suspended solids should not exceed 5 mg/L, with a maximum of 5 microns particle size, under matrix injection conditions while oil content should be limited to below 30-50 ppm. Tolerance for TSS can be relaxed to 10ppm – 50ppm at fracturing conditions, depending on the reservoir parameters and process systems. The knowledge of these parameters should drive the technology selection for optimum water treatment and injection.
Understanding the complexity in the distribution of hydrocarbon in a simple structure with flow baffles and connectivity issues is critical in targeting and developing the remaining pay in a mature asset. Subtle facies changes (heterogeneity) can have drastic impact on reservoir fluids movement, and this can be crucial to identifying sweet spots in mature fields. This study evaluated selected reservoirs in Ovhor Field, Niger Delta, Nigeria with the objective of optimising production from the field by targeting undeveloped oil reserves or bypassed pay and gaining an improved understanding of the selected reservoirs to increase the company's reserves limits. The task at the Ovhor field, is complicated by poor stratigraphic seismic resolution over the field. 3-D geological (Sedimentology and stratigraphy) interpretation, Quantitative interpretation results and proper understanding of production data have been used in recognizing flow baffles and undeveloped compartments in the field. The full field 3-D model was constructed in such a way as to capture heterogeneities and the various compartments in the field. This was crucial to aid the simulation of fluid flow in the field for proper history matching, future production, prediction and design of well trajectories to adequately target undeveloped oil in the field. Reservoir property models (Porosity, Permeability and Net-To-Gross) were constructed by biasing log interpreted properties to a defined environment of deposition model whose interpretation captured the heterogeneities expected in the studied reservoirs. At least, two scenarios were modelled for the studied reservoirs to capture the range of uncertainties. This integrated approach led to the identification of bypassed oil in some areas of the selected reservoirs and an improved understanding of the studied reservoirs. Dynamic simulation and production forecast on the 4 reservoirs gave an undeveloped reserve of about 3.82 MMstb from two (2) identified oil restoration activities. These activities included side-tracking and re-perforation of existing wells. New wells have been drilled to test the results of our studies and the results confirmed our findings.
The largest component of operating costs in most matured assets utilizing 3rd party evacuation infrastructure is crude handling charges. In mature fields with significant water production, water volumes could easily account for over half of crude handling costs. Produced water re-injection for disposal has become a popular strategy for optimizing liquid handling cost as well as supporting environmental responsibility. Injectivity for water disposal wells have been demonstrated to decline with time, the most common factor being permeability reduction arising mostly from fines migration, suspended and dissolved solids in injected water, microbial activities, oil in water and cation concentrations, etc. Thus, Injection wells typically require intermittent stimulation to restore or improve injectivity. Fracturing has been demonstrated to prolong injectivity. However, sustainability is greatly affected by ability to keep fractures open after shut-ins and limited by environmental regulations. Understanding the key mechanisms that lead to injectivity decline will help optimize produced water reinjection systems, enable proactive intervention planning, thus improve injectivity and well availability. In this work we present the development of an injectivity modelling and simulation tool called IDS based on relatively recent injectivity models. Testing and validation of the tool using standard data and an active onshore Niger-Delta Produced Water Reinjection Project as a case study are presented. An outstanding feature of this simulator is its ability to estimate missing parameters or those whose values are not known to high fidelity via history matching. The resulting nonlinear regression problem is solved using a trust-region reflective approach. Decline mechanism regression parameters were similar for a well that had multiple injection periods. Transition time from deep bed to external cake is very sensitive to Total Suspended Solids (TSS) in injected water. Injectivity half-life could increase by as much as 100% for about a 100% drop in mean TSS concentration. The IDS tool was used to predict the injectivity half-life of Well A in the water disposal project.
Recent advances in computing speed and software call for a better practical approach to subsurfacesurface network modelling. Looking at it from the angle of Integrated Asset management, which requires the subsurface and surface teams to work as one in providing input and solution to field development plan challenges, this comes as an important tool in long term planning of a project. With this approach, team members from various disciplines, will be able to work directly with others, sharing ideas and making real time decisions on a regular basis.The case study in this paper shows how such integration resulted in time and cost savings when good and quick decisions are made on a project. this shows a clear departure from the traditional subsurface/surface engineering relation in field development studies, where the subsurface reservoir simulation work is done independent of surface considerations. This paper highlights the benefits of the new approach to the project.
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