This paper discusses the evolution of an Alkaline Surfactant Polymer (ASP) formulation for a challenging sandstone reservoir in North Kuwait. This is an on-shore reservoir, with no gas cap, featuring a moderately high residual oil saturation to waterflood of approximately 20-30%. Moreover, the reservoir has a light oil (API Gravity 30-35) with low Total Acid Number (TAN) and is undergoing a maturing waterflood – thus making it amenable to ASP implementation. However, the high reservoir temperature (90°C), in-situ brine salinity (>250,000 ppm) and divalent ion concentration (>20,000 ppm) place the reservoir at the upper threshold of ASP technology implementation. In addition, the oil has a high emulsification tendency and was observed to form very stable brine-oil emulsions when sampled from the field. This was due to the high concentration of heavier components such as waxes, resins and asphaltenes, some of which are surface-active and tend to interfere with the action of synthetic surfactant at the oil-water interface making ASP formulation development for such oils very challenging. Furthermore, addition of polymer to improve the ASP/oil mobility ratio caused phase separation of the aqueous phase likely because the water-soluble polymer preferentially dissolves in brine while pushing out the hydrophobic surfactant. The methodology followed in this work was to select a surfactant with a high alkyl tail length to solubilize the heavier hydrocarbons in the oil, blend it with a more hydrophilic surfactant to increase the optimal salinity to match the target injection water salinity and overcome the surfactant phase separation issue when polymer was added to the formulation. The ASP formulation was successfully tested in the field in a Single Well Chemical Tracer Test (SWCTT) and was successful in reducing the remaining oil saturation from 0.24 ± 0.02 at the end of water flood to 0.06 ± 0.05 at the end of the chemical flood.
In a thermal Enhanced Oil Recovery project of Kuwait, the static reservoir description uncertainties were identified based on initial static description. The associated development impact and possible risks to the project is then evaluated using a commercial uncertainty analysis tool through simulation studies. Field dynamic testing results from the ongoing Cyclic Steam Stimulation(CSS) pilots and other dynamic testing data were then used to evaluate the static description uncertainties, for an improved reservoir description. The observation from the study is extremely important in not only having an improved understanding of the reservoir description of the subject field but has wider implications in similar reservoir set ups in other parts of the globe. The observations from the pilot operation and simulation history matching clearly demonstrates that local reservoir set up plays a crucial role in each thermal project and understanding them is extremely important for success of the project. The results of the study demonstrate the importance of integrating dynamic cyclic steam stimulation testing results with preliminary static description, to arrive at an improved reservoir description. The technology of thermal Enhanced Oil Recovery (EOR) is an old concept but its application in different reservoir set ups give rise to new learning that widens the knowledge base in the industry. The reservoir being developed in Kuwait is considered a challenging one from many of the classical screening concepts. The success of some of the experiments tried in this project and the learning from their success has wider potentials in similar complex thermal developments.
Selection of adequate thermal operating parameters to ensure fluid containment and cap rock integrity under high-temperature, high-pressure steam injection is vitally important. Cap rock integrity is controlled by the mechanical properties of the rocks and the in-situ and applied stresses resulting from field operations. This paper describes recent minifrac tests carried out in the Lower Fars formation in South Ratqa Field in northern Kuwait to determine the in-situ stresses. The main objective of the field tests was to obtain the minimum horizontal stress using a variety of Before Closure Analysis (BCA) techniques. A secondary objective was to perform After Closure Analysis (ACA) to obtain reservoir parameters such as permeability and initial pressure. All of this data is used as input into subsequent geomechanical studies. For BCA, it is important to identify various fluid flow regimes in the fall-off portions of the tests. The end of particular flow regimes indicates fracture closure. Fracture closure and the resultant minimum horizontal stress are therefore based on sound engineering principles. The cases presented in this paper provide further evidences that a combination of various techniques is the best approach to identify the minimum horizontal stress. No single methodology provides a reliable answer in all cases. Field examples are given to illustrate the practical application of these techniques.
The Sabriyah Upper Burgan is a major oil reservoir in North Kuwait with high oil saturation and is currently considered for mobility control via polymer flooding. Although there is high confidence in the selected technology, there are technological and geologic challenges that must be understood to transition towards phased commercial field development. Engineering and geologic screening suggested that chemical flood technologies were superior to either miscible gas or waterflood technologies. Of the chemical flood technologies, mobility control flooding was considered the best choice due to available water ion composition and total dissolved solids (TDS). Evaluation of operational and economic considerations were instrumental in recommending mobility control polymer flooding for pilot testing. Laboratory selected acceptable polymer for use with coreflood incremental oil recovery being up to 9% OOIP. Numerical simulation recommended two commercial size pilots, a 3-pattern and a 5-pattern of irregular five spots, with forecast incremental oil recovery factors of 5.6% OOIP over waterflood. Geologic uncertainty is the greatest challenge in the oil and gas industry, which is exacerbated with any EOR project. Screening of the Upper Burgan reservoirs indicates that UB4 channel sands are the best candidates for EOR technologies. Reservoir quality is excellent and there is sufficient reservoir volume in the northwest quadrant of the field to justify not only a pilot but also future expansion. There is a limited edge water drive of unknown strength that will need to be assessed. The channel facies sandstones have porosities of +25%, permeabilities in the Darcy range, and initial oil saturations of +90%. Pore volume (PV) of the two recommended pilot varies from 29 to 45 million barrels. A total of 0.7 PV of polymer is expected to be injected in 5.6 and 7.9 years for the 3-pattern pilot and the 5-pattern pilot, respectively, with a water drive flush to follow for an additional 5 to 7 years. Incremental cost per incremental barrel of oil of a mobility control polymer flood which includes OPEX and CAPEX costs is $20 (USD). This paper evaluates the (commercial size) pilot design and addresses field development uncertainties.
scite is a Brooklyn-based organization that helps researchers better discover and understand research articles through Smart Citations–citations that display the context of the citation and describe whether the article provides supporting or contrasting evidence. scite is used by students and researchers from around the world and is funded in part by the National Science Foundation and the National Institute on Drug Abuse of the National Institutes of Health.
hi@scite.ai
10624 S. Eastern Ave., Ste. A-614
Henderson, NV 89052, USA
Copyright © 2024 scite LLC. All rights reserved.
Made with 💙 for researchers
Part of the Research Solutions Family.