Efficient production of heavy oil from the reservoirs with strong bottom aquifer has proven to be a challenge. While providing enough energy to produce the field under the primary depletion, the strong bottom aquifer in combination with unfavorable oil/water mobility contrast leads to rapid development of water coning thereby limiting oil recovery. Drilling of long horizontal producing wells in the upper part of the oil column maximizes the distance from the aquifer and allows relatively high production rates. This slows down the water cone development and increases primary recovery. Even with further optimization of the primary production, the recovery factor remains relatively low and consequently application of Enhanced Oil Recovery (EOR) techniques is required to increase the recovery. Сrude oil from Nimr-E field is medium-heavy with the viscosity of 250-700cP under reservoir conditions. The field has been developed with mostly horizontal producing wells with relatively short inter-well distance. Due to strong bottom aquifer the reservoir pressure is maintained at the initial level despite the production under primary depletion. To increase the recovery factor polymer flooding was selected with expectation to increase the recovery by 5-10%. A field trial was conducted to understand the influence of polymer injection on oil recovery and address major uncertainties identified as key enablers for the full-field project. The pilot surveillance program, the surface facilities and the subsurface configurations were specifically designed to meet these objectives. The paper presents field data of polymer injection trial in Nimr field and focuses on the performance results and principal operational challenges. The injection of polymer resulted in the incremental oil production that was assessed using field data and simulations. A significant increase of initial oil production and clear watercut reversal due to polymer injection was observed and incremental recovery reached approximately 7% of the initial oil in place. Injectivity issues encountered in the pilot wells were mitigated by the techniques and chemicals developed to solve the issues. The results prove the subsurface and operational success of polymer field trial that leads the way to a commercial development.
MY01 is an offshore field located in Malaysia. Although souring mitigation by nitrate injection was applied from the start of the seawater flood, hydrogen sulphide (H2S) has been detected in several producers after injected seawater breakthrough. The objectives of this work are to understand the causes of reservoir souring in MY01 and to provide key considerations for improving souring prediction in low temperature reservoirs, as generalised from the learnings from this field. Reservoir souring potential was assessed using a Joint Industrial Project (JIP) developed program (SourSimRL). SourSimRL is a reservoir model post-processor which simulates the microbial generation, scavenging, adsorption and transport processes of H2S in fields subjected to waterflood, based on fluid dynamics, reservoir conditions and water chemistries as dictated by the reservoir model. The MY01 reservoir model was split into two parts: (i) a history matched model that allows calibration on reservoir souring simulator input parameters; and (ii) a forecast model on which souring development is predicted. Extensive sensitivity studies were conducted to define key factors promoting or inhibiting H2S production to match the actual H2S levels seen in the producers. Furthermore, the application of microbiological analysis to understand the reservoir souring behaviour, including screening of bacteria present using DNA-based techniques is also discussed. The simulations demonstrated that carbon is the souring limiting factor in MY01. To match the H2S field data, other metabolisable carbon sources should be available in addition to the volatile fatty acids (VFA's) in the formation water. The souring development in such field could be driven by the mechanism of the carbon supply. Therefore, it is critical to identify the type and quantify the level of dissolved organic carbon, including oil-derived BTEX or microbial degradation products. Since MY01 reservoir conditions are favourable for souring activities, microbial development is likely to take place both in the biofilm that forms at the injector face as well as at flood fronts deeper into the reservoir.
In Southern Oman, PDO is producing from several critically sour fields (1-10% H2S). Initial flow assurance studies from these fields based on available data at the time did not predict asphaltene plugging issues in depletion mode for most of the fields. However, over the period, wells from one particular field (Field SA3) started experiencing asphaltene deposition in the wellbore, which initially affected only surveillance activities but later led to significant production deferment and posed operational challenges. This paper discusses the asphaltene management strategy developed by the team to tackle asphaltene problem in a systematic manner by improving the current asphaltene detection and cleanout techniques, which led to to reduction in unscheduled deferment by ~50% and the intervention costs by ~20-25%. This work also describes the potential asphaltene risks during gas injection based on an asphaltene study performed on downhole samples.
The effectiveness of a low complexity chemical flooding formulation that was developed for application in offshore environments was evaluated in a single well test offshore South China Sea. The SP formulation uses seawater with no additional water treatment beyond that which is normally performed for water flooding (filtration, de-oxygenation, etc.). The ability to use a formulation based on only seawater avoids water treatment and reduces complexity for commercial implementation. The Single Well Test was conducted in an existing producer with its wellhead on an existing production platform offshore. The injection facilities were placed on work barge that also had accommodation to house the people that executed the injection test. The facilities on the barge consisted of seawater lift and filtering equipment, surfactant and polymer mixing capability, and high-pressure pumps to deliver the mixed fluids through a flexible high-pressure hose to the platform. A laboratory to support the QA/QC of the injected fluids was also installed on the barge. Standard Single Well Chemical Tracer test procedures were applied to determine the remaining oil saturation after waterflood and after injection of the SP formulation. The Single Well Test was completed in accordance with the objective without any recordable HSSE cases ahead of schedule. The composition of the injected SP formulation was well within the specifications resulting in good injectivity of the formulation. The single well tracer tests conducted after the SP and polymer injection indicate that the residual oil saturation was reduced to values between 7-9% (Sorc). The main contributions described in the paper are: demonstration that a seawater-based SP formulation can be effectively mixed and injected from a barge offshore. the interpretation of the single well tracer tests conducted after the SP and polymer injection indicate that the residual oil saturation was reduced to values similar to those observed in core floods with the SP formulation in the laboratory.
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