The concept of uncertainty, risk, and probabilistic assessment is increasingly employed as a standard in the E&P industry to assist in optimum development and investment decisions. The studied Onshore Abu Dhabi field is a Cretaceous complex carbonate oil producing reservoir, which has more than 15 years of production history. This paper discusses an integrated static and dynamic workflow to create a range of probabilistic simulation models to forecast oil production under several production schemes. The study deals with quantitative identification and ranking of factors affecting volumetric and reserves uncertainty in the field. In order to quantify the uncertainties, the main uncertainty parameters and their respective ranges were first identified, selected, and analyzed using Experimental Design to generate a tornado plot which enables the selection of the most influential parameters on the objective function. Secondly was to build a Proxy Model that would help in defining the full probabilistic volumetric distribution on the stock tank oil initial in place (STOIIP) and Recovery Factor (RF). Five main static uncertainty parameters were selected to assess the STOIIP distribution namely structure, free water level, saturation height function, porosity, and formation volume factor. In addition, four dynamic uncertainty parameters were incorporated for reserves estimation specifically Sorw, Kv/Kh, relative permeability, and subdense layer communication. A cumulative distribution function was created in order to extract the probability cases of P10, P50 and P90 of the STOIIP. The simulation models were then built using the P50 volumetric case derived from the static model that was run with hundreds of realizations. Combinations of dynamic uncertainty parameters were simulated using Monte Carlo to define the Low, Base, and High Cases. This was done by comparison with material balance computations and streamline simulation. A stochastic combination of the STOIIP distribution and the RF sensitivities was done through an Experimental Design, Proxy Model, and Monte Carlo approaches. The Base Case model history-match was checked against the choice of parameters defining the Low and High sensitivity cases. The match data available included: oil rates, water cuts, GOR, WHP, flowing and static Pressure, and saturation profiles derived from open and/or cased hole logs. The sensitivity assessment showed that using currently available data, the two major factors affecting the volumetric uncertainty are the free water level and structure. In contrast, porosity possesses the smallest impact. In addition, Kv/Kh and relative permeability are the two main parameters affecting the RF. A number of appraisal wells will be drilled to reduce the structure uncertainty specifically in the flank areas, which will lead to further maturation of reserves. Economic calculations were performed to check that all projects pertaining to the reserves category would consider oil price, CAPEX profile, OPEX profile, well and facility life time.

The paper is continuation of SPE-175682 and SPE-182963. This work illustrates horizontal well placement optimization studies conducted on a Cretaceous complex carbonate reservoir with thin oil column and strong water drive reservoir. A further complication for the well placement is the presence of some thin high permeability streaks intervals with permeability value of up to 1 Darcy. Early water breakthrough encountered in the existing oil producers is a serious problem which results in lower oil production rates, lower oil recovery, and increased lifting cost. In addition, premature water breakthrough would leave behind bypassed oil zones. Hence determining the optimum location of the wells is a critical and crucial decision to be made during a field development plan. In this study, we apply integrated geosciences, geostatistical, and flow simulations to assess options for well placement. Base case porosity, permeability, and water saturation realization was selected from multi-realizations performed in the static model which was then used for sensitivity in fluid flow simulations. Flow simulation was used to analyze the performance of the well considering horizontal wells length, well azimuth, well inclination, wells position relative to the reservoir top as well as its position relative to the water contact. In addition, multi-scenarios of well placement relative to the high permeability intervals were created to see the impact on the oil rate, plateau, and water breakthrough time. The flow simulation results show that the 4000 feet horizontal well that penetrating the upper high permeability streak gives the best performance in most of the cases. In contrast, the performance of the horizontal wells deteriorated rapidly once the well hit the lower high permeability streaks. Some producers in the studied reservoirs have been drilled using the multidiscipline study recommendation. Actual property derived from the newly drilled wells displayed a very reasonable match to the expected property from model. In addition, production test and well commissioning result also showed comparable match with what was expected from dynamic simulation.

Water alternating gas (WAG) is employed to improve flood mobility, and sweep efficiency during gas injection by squeezing more oil out of the reservoir. Injected water sweeps the lower part of the reservoir, while gas tends to sweep the upper part due to gravitational forces. Accurate mapping of fluids and their distribution across the reservoir is an important aspect of characterizing reservoir properties. Understanding the performance of the injected fluids, and their flow pattern is critical to understand reservoir behavior, the interaction between the fluids at reservoir level, and quality check the reservoir dynamic model. Techniques such as tracer injection and time lapse logging are utilized as a method to monitor, and confirm flood front arrival. Pulse neutron decay time log (PNL) is a common method used to monitor reservoir fluid movement behind casing. Multi detector pulse neutron decay improves the tool capabilities and enhances its potential in detecting gas flood front and its miscibility. Interpreting reservoir monitoring logs requires combining the innovative knowledge on the tool physics and understanding reservoir properties. Integrating all available data is an important step towards the correct interpretation. Multi detector neutron pulse decay was run in time lapse logging using same tool provider to allow consistency. The tool has successfully mapped the approach of injected gas, it clearly showed the change in fluid properties over time, and most importantly has shown the type of fluid approaching. Few months later gas tracer was found in the close-by producer. This paper shows a case study of successful integration of the results of six years’ time lapse logging with the dynamic simulation model, in a field located onshore Abu Dhabi UAE, and subject to rich gas EOR recovery through WAG cycling system. Gas tracer and PNL were used to monitor the flood front and break through. The flood movement mapped from neutron pulse decay with time lapse, was successfully history matched in the dynamic simulation model. The calibrated simulation model is used to monitor the further advancement of flood front.