Laboratory experiments and simulations showed that for an Austrian oil reservoir, oil recovery can be significantly increased using polymers. One of the key design parameters for optimizing displacement efficiency while minimizing costs is the in-situ viscosity of the polymer solutions.Whereas the viscosity of polymer solutions can be measured at surface, the viscosity in the reservoir is difficult to estimate due to degradation of the polymers during the injection process. In addition, polymers exhibit non-Newtonian behaviours resulting in different viscosities of the polymer solutions depending on the shear rate in the reservoir.For the Austrian reservoir, water injection fall off tests were available. A simulation model was calibrated with these tests, and used to simulate injections of polymer solutions followed by fall offs. Simulation results indicate that water injection and fall off tests followed by a series of polymer injection and fall off tests can be interpreted to determine the in-situ viscosity of polymer solutions and the radius of the polymer front with reasonable accuracy, even in the case of non-Newtonian shear-thinning behaviour.Being able to determine the in-situ viscosity allows modifying the injection programme ( changing pumps, modifying perforations) if the degradation of the polymer viscosity is found to be significant, and adjusting the polymer concentration to improve stability and efficiency of the displacement process.
Polymer injection pilot projects aim at reducing the uncertainty and risk of full-field polymer flood implementation. The interpretation of polymer pilot projects is challenging owing to the complexity of the process and fluids moving out of the polymer pilot area. The interpretation is increasingly more complicated with the heterogeneity of the reservoir.In the polymer pilot performed in the 8 TH reservoir of the Matzen Field in Austria, a polymer injection well surrounded by a number of production wells was selected. A tracer was injected one week prior to polymer injection. The tracer showed that the flow-field in the reservoir was dramatically modified with increasing amounts of polymers injected. Despite short breakthrough times of 4-10 weeks observed for the tracer, polymer breakthrough occurred only after more than 12 months although injection and production rates have not been substantially changed.The tracer signal indicated that the reservoir is heterogeneous with high flow velocities occurring in high permeable layers. By injecting polymers, the mobility of the polymer augmented water was reduced compared with water injection and lead to flow diversion into adjacent layers. The tracer response showed that the speed of the tracer moving from injection to production wells was reduced with increasing amount of polymers injected.This response was used to assess the changes of the amount of water flowing from injection to production well. After a match for the tracer curve was obtained, adsorption, residual resistance factor and dispersivity were calculated. The results showed that even for heterogeneous reservoirs without having good conformance of the pilot, the critical parameters for polymer injection projects can be assessed by analyzing tracer and polymer response. These parameters are required to determine whether implementation of polymer injection at field scale is economically attractive.Along the flow path, an incremental recovery of about 8 % was achieved. The polymer retention and inaccessible pore volume in the reservoir was in the same range as in core floods. Incremental oil recovery owing to acceleration along the flow path was estimated at contributing to about 30 % to the overall incremental oil production due to polymer injection and 70 % to improved sweep efficiency.
Currently, OMV is performing a polymer solution injection pilot test into the 8 TH reservoir of the Matzen field in Austria. The reservoir is a heterogeneous sandstone, tracer tests revealed that the difference in flow velocity is more than a factor ten. The observed large heterogeneity and fast travel times raised the questions: what are the effects of the heterogeneity and non-Newtonian polymer rheology on the displacement efficiency?Laboratory experiments were performed to investigate the rheology and retention of the high molecular weight polyacrylamide polymer solution. The experiments showed no significant retention. The rheology of the injected polymers indicated apparent shear-thickening with flow velocity. The effect of permeability on the apparent viscosity was larger than the apparent shear-thickening.The results of the tracer tests and laboratory experiments were used in simulations of layered reservoirs with the properties of the 8 TH reservoir. Newtonian, shear-thinning and shear-thickening polymer solution rheology was applied for cases with and without crossflow.Without crossflow, the highest incremental oil recovery factor is seen for shear-thickening behavior and the lowest for shear-thinning. The utility factor (u f ϭ kg polymer injected/incremental barrels of oil production) is showing a minimum as a function of polymer injection slug size whereas the incremental recovery factor is increasing up to a polymer slug size of 1.2 PV injected.With crossflow: in this case, the incremental oil recovery compared with the water flood is highest for shear-thinning followed by Newtonian and shear thickening behavior. The shear-thinning fluid travels faster in the high permeability channel, resulting in substantial cross flow of the polymer solution into the adjacent low permeability area. The cross-flow dominates over the effect of the polymers traveling at different speeds. The incremental oil recovery and utility factor are increasing with the slug size for all cases. Larger slug sizes of polymer injection result in higher utility factors and higher incremental oil recovery.It should be noted that the influence of permeability on apparent viscosity of the polymer solution rheology is larger than the shear-thickening effects. Hence, although apparent shear-thickening might be observed in the laboratory for one lithology, the apparent viscosity in the reservoir might be higher in lower permeable layers despite the lower flow velocity than in high permeable layers.Varying a number of parameters, the results indicate that the permeability contrast of high permeability and low permeability is not the most influential parameter for polymer solution projects in reservoirs with crossflow. Higher permeability contrast leads to poorer sweep efficiency of the water flood to which the polymer augmented flood is compared to. More oil is remaining in the reservoir for larger permeability contrast, polymer flooding tends to lead to increased incremental recovery factor with larger permeability contrast for the conditi...
Summary Polymer-injection pilot projects aim at reducing the uncertainty and risk of full-field polymer-flood implementation. The interpretation of polymer-pilot projects is challenging because of the complexity of the process and fluids moving out of the polymer-pilot area. The interpretation is increasingly more complicated with the heterogeneity of the reservoir. In the polymer pilot performed in the 8 Torton Horizon (TH) reservoir of the Matzen field in Austria, a polymer-injection well surrounded by a number of production wells was selected. A tracer was injected 1 week before polymer injection. The tracer showed that the flow field in the reservoir was dramatically modified with increasing amounts of polymer injected. Despite short breakthrough times of 4 to 10 weeks observed for the tracer, polymer breakthrough occurred only after more than 12 months although injection and production rates were not substantially changed. The tracer signal indicated that the reservoir is heterogeneous, with high flow velocities occurring along a number of flow paths with a limited volume that are strongly connecting the injection and production wells. By injecting polymers, the mobility of the polymer-augmented water was reduced compared with water injection, and led to flow diversion into adjacent layers. The tracer response showed that the speed of the tracer moving from injection to production wells was reduced with increasing amount of polymer injected. This response was used to assess the changes of the amount of water flowing from the injection well to production wells. After a match for the tracer curve was obtained, adsorption, residual resistance factor (RRF), and dispersivity were calculated. The results showed that, even for heterogeneous reservoirs without good conformance of the pilot, the critical parameters for polymer-injection projects can be assessed by analyzing tracer and polymer response. These parameters are required to determine whether implementation of polymer injection at field scale is economically attractive. Along the flow path that is connecting injection and production well, as shown by the tracer response, an incremental recovery of approximately 8% was achieved. The polymer retention and inaccessible pore volume (IPV) in the reservoir were in the same range as in corefloods. Incremental oil recovery caused by acceleration along the flow path was estimated at approximately 20% of the overall incremental oil production caused by polymer injection and 80% was attributed to improved sweep efficiency.
The development of marginal volumes in the Jasmine field is part of Mubadala Petroleum's overall strategy to extend the field's life. This development is accomplished by progressively exploiting increasingly challenging prospects. This paper highlights two case studies to illustrate how Mubadala Petroleum has successfully developed marginal prospects to unlock the Jasmine field's remaining potential. Prospect identification begins with integrated subsurface studies focusing on contingent resources. Several studies were conducted to determine the right technology to mature these marginal prospects. These prospects often involve the requirement to drill Extended Reach Drilling (ERD) wells. This is due to the fact that some platforms are slot constrained, such that wells cannot always be drilled from the nearest platform. One of Mubadala Petroleum's solutions was to drill a horizontal well with a completion that uses an Autonomous Inflow Control Device (AICD) to optimize and enhance oil production. This combination of AICD and ERD horizontal wells has proven successful in the Jasmine field's continuing development. Two wells in this case studies were drilled during the 2018 and 2019 drilling campaigns, illustrate how marginal volumes are developed in the Jasmine field, with each case having unique objectives and challenges. In 2018, one horizontal well was drilled, with an aim to enhance recovery efficiency in the viscous oil reservoir. The well was drilled close to the top reservoir, AICD devices were installed in conjunction with a sand screen to delay water breakthrough, and the well has been in production for two years. The overall strategy was effective in delaying water breakthrough. In 2019, a horizontal well was drilled to develop a relatively small 14ft oil rim below a thick gas cap reservoir. This well was the longest ERD well in the Gulf of Thailand. The well was also successfully drilled and geosteered at 4-5 ft TVD below the gas cap. AICD's were installed to balance the gas cap expansion and aquifer support to optimize oil production. The well has produced at a stable oil rate of 500-600 bbls per day with minimal gas and water production, up to the present date, confirming the validity of AICD technology in reducing the production of unwanted fluids. The AICD has been shown to play a significant role in optimizing production in reservoirs with small oil rims and thick gas caps. AICD completions also help to enhance production recovery from viscous oil reservoirs. Moreover, ERD drilling has improved the feasibility of several remote prospects and minimized the slot availability constraint in the Jasmine field.
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