Polymer injection in the south of Sultanate of Oman has been implemented in Marmul field for the last decade. Recently, alkaline surfactant polymer (ASP) technology has also been piloted in the field, which was technically successful owing to its significant incremental oil production. The current end-game strategy for the field is to follow polymer with ASP flood in order to produce the remaining oil after polymer flood and maximize the ultimate oil recovery factor. This has revealed the need for evaluation of the full-field performance of ASP flood using available tools. Full-field dynamic models are not always best tools for modeling the performance of chemical enhanced oil recovery, primarily due to under-representation of the reservoir heterogeneity, lack of the complementary data, complexity of the process itself, and large computation time. In this paper, we implement a conduit-model approach using field production data from the ASP pilot to assess the ultimate incremental oil recovery. This approach is compared to an analytical model that is based on the modified Koval’s method with reservoir heterogeneity as an input parameter. The obtained results are used for preliminary assessment of the difference between polymer and ASP injection in the full field.
Polymer flooding has been identified as the next phase of developing two heavy oil fields located in the South of the Sultanate of Oman. The fields are supported with a strong bottom aquifer drive that results in large amount of water production due to the adverse mobility. In order to prove the concept of polymer sweep, a field trial was designed and conducted successfully in the field. Moreover, due to the challenges associated to handling back produced polymer number of tests were conducted to assess the impact of polymer on facilitates. Development of the field will take place in a phased manner in order to reduce the capex exposure, maximize the utilization of the existing facility and managing project risks while contributing to the overall production.
Dynamic modeling of both fields showed that polymer development is feasible. The modeling work was supported by a field trial that was designed to prove: polymer sweep performance, injectivity, as well as polymer losses to the strong water aquifer. This trial was monitored with detailed surveillance program including pressure, injection/production rates, viscosity and water quality, which concluded incremental oil gain from the process. In parallel, a number of laboratory and field tests were performed to assess the impact of polymer on the surface facilities such as the heater, separation tanks and the growth of the reed beds - wet planets- in the field.
Sustained incremental oil gain was clearly observed from polymer injection in the field trial. Injectivity could not be maintained as planned, due to a combination of polymer, biological and water quality issues. Later tests including biocide injection and QA/QC of polymer batches as well as some well stimulation did show improved injectivity profiles. Demulsifier tests mitigated the risk of creating stable emulsions. Laboratory tests indicated no heater fouling observed below 150°C. Short and long term investigation into the impact of water- contaminated polymer on plants in the wet lands was positive with the plants showing no necrosis. This was tested up to back produce polymer concentration levels of 500 ppm. Which is achievable given the excessive amount of water received at the facility allowing the dilution of back produced polymer to the required level. This helped in making the project more economically attractive as it results in a saving of around 30% from the overall project Capex.
The modeling exercise proposed drilling of around 200 polymer injectors across both fields, but in order to manage costs and further reduce project risks an optimised phased development approach was evaluated. Both Analytical and modeling approach were used to identify the phasing strategy. The phasing strategy will start with the most attractive to least attractive areas allowing for appraisal these areas prior to committing to their development. The key enabler for phasing of this development is by standardizing and replicating the development. Hence, modular facility for polymer preparation and injection was selected, in which a detailed design will be conducted for the first phase then it will be replicated for the other upcoming phases.
Phase-1 of the development will be in the central area as it is has a better response from the model compared to the other areas. This phase will include the drilling of 25 injectors and it will require two modular facilities. 25 to 30 injectors will subsequently be drilled every 2 years for the follow up phases.
The different surface and subsurface tests paved the way for a full field implementation of polymer injection in structures with strong bottom water aquifer. The paper discusses the phasing and replication strategy to mitigate project risks, learn on the go and improve the project’s schedules and economics.
Full field polymer flood has been identified as a potential EOR process for a heavy oil field with a strong bottom aquifer in the South of the Sultanate of Oman. A number of surface and subsurface risks have been identified prior to field implementation, including matrix injectivity, polymer sweep and impact of back produced polymer on surface facility & the field wet lands (reed beds). The development of the field will take a place in a phased manner in order to reduce the capex exposure, maximize the utilization of existing facility and managing project risks while contributing to the overall production. In order to support the standardization and steer the future phases the modular facility concept was selected as basis for polymer preparation and injection facilities, this design was made flexible enough to cater for a wide range of possible trial outcomes.
A very comprehensive polymer pilot was performed in this dome-shaped heavy oil reservoir to assess polymer sweep performance as well as losses to the strong water aquifer. An inclusive real-time surveillance programme was executed to monitor key parameters including pressure, injection/production rates, viscosity and water quality, which concluded incremental oil gain from the process. Other tests were conducted to assess the impact of back produced polymer on growth of plants, heater fouling and surface facility separation tanks. In general, all results were positive which paved the way for field-wide development of polymer flooding with less Capex requirement.
A sustained incremental oil gain was clearly observed from polymer injection, which was supported by saturation logs acquired from the observation wells. Injectivity could not be maintained as planned, due to a combination of polymer, biological and water quality issues. Later tests including biocide injection and QA/QC of polymer batches as well as some well stimulation did show improved injectivity profiles. Demulsifier tests mitigated the risk of creating stable emulsions. Lab tests indicated no heater fouling observed below 150°Cdeg. Short and long term investigation into the impact of water-contaminated polymer on plants in the wet lands was positive with the plants showing no necrosis with back produced polymer concentrations up to 500 ppm which is achievable given the excessive amount of water received at the facility level that dilute the back produced polymer. This helped in making the project more economically attractive as it results of a saving of around 30% from the overall project Capex.
The different surface and subsurface tests paved the way for a full field implementation of polymer injection in structures with strong bottom water aquifer. The paper discusses the phasing that was purused to mitigate risks, learn on the go and improve the project economics
The Marmul inverted five-spot pilot was successfully completed in 2016, demonstrating the effectiveness of Alkaline Surfactant Polymer (ASP) flooding in improving oil recovery from Al khalata reservoir. Earlier studies including core flood experiments, single well chemical tracer tests and small scale models indicated a potential of >10% of ASP incremental recovery over polymer flood and >20% over water flood. The pilot included a custom-built ASP facility, a first of its kind of scale squeeze treatment for high pH, state-of-the-art nuclear magnetic resonance (NMR) technology for vertical saturation estimates and very extensive sampling and surveillance programme. Overall, the pilot operation was very smooth and stable, achieving high facility uptime, good injectivity, accurate chemical dosing and met the surveillance target.
The estimated ASP incremental recovery from the pilot was over 30%, which increased the interest in a field-wide ASP injection. The acquired pilot results and operation experience were used to scale up the facilities design and assess the impact of key uncertainties observed in the field and the lab. Major factors influencing the recovery factor and project efficiency were analysed including chemicals formulation, facilities design and water treatment technologies. A mind-shift on the formulation cocktail and facilities design was proposed to improve the economic attractiveness of the process on large scale implementations. A phased development is proposed to de-risk subsurface and surface concepts which are different from those in the pilot.
This paper discusses in brief the pilot operation & performance, scaling up the results to full field implementation and key design considerations for a cost effective ASP project.
This paper presents laboratory studies to apply a new approach based on combined foam EOR processes to a naturally fractured carbonate reservoir (NFR) located in Oman. Applications of EOR techniques in fractured reservoirs, despite their attractive potential, have always been challenged by the inability to efficiently control EOR fluid mobility in fractures, which results in inefficient flooding of the reservoir matrix and poor economics of the process. This work discusses the maturation of efficient foam EOR processes for NFRs. The foam is aimed at blocking aqueous solution flow in fractures on the one hand while allowing low interfacial tension (IFT) solution to enter the matrix on the other hand.
We use an extensive experimental workflow to develop such solution in the challenging salinity conditions of the considered reservoir. Using robotics, we first combine low-IFT and foam boosting surfactants to come up with the most adapted chemical cocktail in terms of solubility, IFT with crude oil and foaming properties in hard brine. The selected formulation is then quantitatively characterized for IFT with crude oil, phase behavior with live oil, foam stability in reservoir pressure and temperature conditions, and foaming properties in model porous media. Dedicated coreflood experiments mimicking flow in fractured reservoirs are finally used to quantitatively evaluate the process using the designed formulation. This includes evaluation of foam-induced pressure drop, effluent fluid composition and oil recovery in artificially fractured cores.
The designed combined foam EOR formulation is perfectly soluble in hard brine and yields an IFT with crude oil well below 10-2 mN/m at 65°C. It is able to generate and stabilize foam both in absence and in presence of crude oil. Process evaluation in artificially fractured core shows good control by foam of aqueous solution mobility in fracture, and efficient imbibition of aqueous solution from fracture to matrix. Interestingly, a filtration effect is observed whereby only aqueous solution enters the matrix from the fracture, while foam only exists in fracture. This, combined with the sensitivity of foam to presence of oil, enables an efficient production of oil from the matrix through the fracture, as measured during recovery experiments.
This paper presents the first steps toward a potential pilot application of a new process aimed at making chemical EOR in fractured carbonate technically and economically feasible. The approach presented here allows the design of a performing process in challenging conditions of water salinity and hardness.
Das, Alolika (The University of Texas at Austin) | Nguyen, Nhut (The University of Texas at Austin) | Alkindi, Abdullah (PDO) | Farajzadeh, Rouhi (Shell Technology Oman) | Azri, Nasser (PDO) | Southwick, Jeffrey (Shell Global Solutions Intl. B.V.) | Vincent-Bonnieu, Sebastien (Shell Global Solutions Intl. B.V.) | Nguyen, Quoc P. (The University of Texas at Austin)
Chemical enhanced oil recovery (EOR) in carbonate reservoirs has always been technically and economically challenging. Conventional Alkaline-Surfactant-Polymer (ASP) flooding has limited application in low permeability (2-20 mD) and high salinity formations (~200,000 ppm TDS) with a large concentration of divalent cations. Also injectivity into such low permeability reservoirs can be a significant problem with polymer solutions.
The process of low tension gas (LTG) in tight carbonates has exhibited good microscopic displacement and mobility control. It combines interfacial tension (IFT) reduction with improved mobility control by in-situ generation of foam in low-permeable heterogeneous formations. This process has been tested in the lab for a Middle Eastern carbonate reservoir, which is the subject of this paper. This strategy has been tested through either co-injection or alternating injection of slug/drive surfactant solution and gas (CO2, N2, or hydrocarbon) at low foam quality (high water content). A successful surfactant screening was performed to select the optimum surfactant formula that exhibits ultra-low IFT, good aqueous stability, and low microemulsion viscosity. The formulation allows tailoring of optimal salinity for ultra-low oil-water IFT to the variation of formation and produced water salinity. Core flood experiments have been performed, which demonstrated favorable mobilization and displacement of residual oil. Tertiary recoveries of up to 85% on remaining oil were achieved for cores with permeability less than 10 mD. An innovative experimental method was also developed to achieve high initial oil saturation in tight rocks.
Alkindi, Abdullah (Petroleum Development Oman) | Al-Azri, Nasser (Petroleum Development Oman) | Said, Dhiya (Petroleum Development Oman) | AlShuaili, Khalid (Petroleum Development Oman) | Te Riele, Paul (Shell Development Oman)
Primary and secondary recovery processes produce about one third of oil in place, leaving significant volumes behind. For low permeability and highly saline carbonate reservoirs, exploiting these resources is often challenging and unfeasible either technically and/or commercially.
In this paper we discuss the application of an emerging EOR technique that has shown promising results in the lab. Di-Methyl Ether (DME) enhanced waterflood (DEW) is a process in which DME is added to injection water, which upon injection into the reservoir, it preferentially partitions into the remaining oil. As a result, it swells the oil and reduces its viscosity which significantly improves oil mobility in the reservoir. Several core-flood experiments conducted in tight carbonate plugs have shown incremental recoveries of up-to 20% post waterflood. Additionally, the process provides significant acceleration to oil production, which would otherwise take several pore volume of water injection.
After successful PVT and core flood experiments, a field trial has been designed to de-risk this technology which if successful would add significant reserves. The pilot will be implemented in a tight carbonate reservoir that has been under waterflood. Some key uncertainties this pilot will address include solvent utilisation, oil incremental recovery, solvent back production and impact of geology on the process.
This paper discusses the key physical mechanisms of the process, pilot design and challenges of full field considerations. In addition, it also highlights key considerations when designing solvent-based EOR applications. The paper also highlights the need of lab work to mitigate operational issues prior to implementation. Calibrated numerical models were used to generate full field profiles, which show the need for a well optimised pattern design to make such processes feasible
A key and challenging issue in the oil and gas industry is Integrated Asset Management, which encompasses efforts from various disciplines to build a single integrated model that describes the whole system. This paper presents an integrated production model (IPM), forecasting workflow and decision making philosophy to develop two complex sour fields comprising three reservoirs in South of Oman. The study involves two sour oil reservoirs (of different PVT properties, H2S concentrations) and drive mechanisms and one sour gas condensate reservoir that is used to complement associated gas to give a constant gas rate for export. Water injection and water handling are parts of the model.
The modelling couples subsurface dynamic 3D models (built using Shell's MoReS reservoir simulator), well models and surface network (built in GAP) and the interactions that occur in the production system. The configuration involves three reservoirs, 19 oil and 3 gas producers, 12 water injectors, one production station, three separators (low, medium and high pressure) and several flow lines of different sizes. The main objective of the study is to optimize the developments of these reservoirs by assessing the best design of surface network (plant capacity). The integration allows to assess the impact of various station capacities; either liquid or/and gas, on the project profitability under different operational scenarios such as injection rate, off-take, artificial lift and well phasing and their impact on CAPEX and OPEX. The model also helps in identifying system bottle-necks, effects of back pressure, mixing of fluids and flow assurance. The use of jet pumps as artificial lift mechanism was successfully imbedded and optimized.
The paper describes the structure of the modelling, surface components, optimization strategy, benefits and challenges of IPM deployment to choose the optimum field design. The results demonstrate the importance and merit of field management in addition to accuracy and rapidness of production forecast.
A set of analog vapor-extraction (VAPEX) laboratory experiments was performed to test the ability of existing analytic and numerical models to predict oil-drainage rates from this process. The selected analog fluids and porous media enabled all input parameters to the analytic model to be determined independently of the analog VAPEX experiments without history matching. The results show that the underprediction of oil rate by the standard analytic model is not because of increased levels of mixing between the solvent and oil over that expected from molecular diffusion and convective dispersion, but rather because of a deficiency in the analytic model formulation.