Polymer injection might lead to incremental oil recovery and increase the value of an asset. Several steps have to be taken to mature a polymer injection project. The field needs to be screened for applicability of polymer injection, laboratory experiments have to be performed, and a pilot project might be required prior to field implementation.
The decision to perform a pilot project can be based on a Value of Information (VoI) calculation. The VoI can be derived by performing a workflow capturing the impact of the range of geological scenarios as well as dynamic and polymer parameters on incremental Net Present Value (NPV). The result of the workflow is a Cumulative Distribution Function (CDF) of NPV linked to prior distributions of model parameters and potential observables from the polymer injection pilot.
The impact of various parameters on the CDF of the field-wide NPV can be analyzed and in turn used to decide on what measurements from the pilot have a strong sensitivity on the NPV CDF and are thus informative. In the case shown here, the water cut reduction in the pilot area has a strong impact on the NPV CDF of the polymer injection field implementation. To extract maximum information, the response of the pilot for water cut reduction needs to be optimized under uncertainty.
To calculate the VoI, the Expected Monetary Value (EMV) difference of a decision tree with and without the pilot can be used if the Decision Maker (DM) is risk neutral. However, if the DM requires hurdle values through a Probability of Economic Success (PES), Value Functions (VF) and Decision Weights according to the Prospect Theory should be used. Applying risk hurdles requires a consistent use of VFs and Decision Weights for calculating VoI and the Probability of Maturation (POM) of projects.
A polymer pilot in the 8 TH reservoir in Austria showed promising results. The Utility Factors were below 2 of kg polymer injected / incremental barrel of oil produced (polymer cost are 2 – 4 USD/kg). Furthermore, substantial incremental oil was produced which might result in economic field implementation. The results triggered the planning for field implementation of polymer flooding.
To optimize the economics of field implementation, a workflow was chosen ensuring that the uncertainty was covered. 1200 geological models were generated covering a variety of different geological concepts. These geological models were clustered based on the dynamic response into 100 representative geological realizations and then used for history matching.
For infill drilling, probabilistic quality maps can be used to find locations. However, injection and production well optimization is more challenging. Introducing probabilistic incremental Net Present Value (NPV) maps allows for selection of locations of injection and production well patterns.
The patterns need to be optimized for geometry and operating parameters under uncertainty. The geometry was optimized in a first step followed by operating parameter optimization. In addition, injectivity effects of vertical and horizontal wells due to the non-Newtonian polymer rheology were evaluated. The last step was full-field simulation using the probabilistic NPV map, optimized well distance and operating parameters.
The resulting Cumulative Distribution Function of incremental NPV showed a Probability of Economic Success (PES) of 91 % and an Expected Monetary Value of 73 mn EUR.
Most of the crude oil is already recovered and discovering new oilfields tend to be challenging and difficult. Implementing an EOR method is essential to enhance the production life of mature oil fields and to make them economically more attractive. Especially, for heavy oil reservoirs chemical flooding is besides thermal methods promising. Only a limited number of alkali flood projects alone are reported worldwide. Phase screening represents the first step of experiments and gives information about the ability of various alkali solutions to generate in-situ surfactants at different concentration ranges.
In this study, carbonate-based alkalis were screened on their effect on in-situ soap generation. Two oil reservoirs both located in the Matzen oil field (Austria) were observed, where an alkali flood project will be realized in the near future. In lab scale, were phase experiments with various concentrations of carbonate-based alkalis (sodium and potassium carbonate) screened at the water-oil-ratio 5:5. Formulations with synthetic and real softened brine were compared, using dead oil and viscosity-matched oil with cyclohexane. Samples were observed over time (100 days) to figure out their equilibrium at reservoir temperature. Afterwards large-scale samples were prepared and viscosity measurements performed.
Potassium carbonate (K2CO3) is not well investigated in the literature as an alkali agent yet. It showed very promising results in all performed trials and generated remarkably more amounts of in-situ surfactants compared to Na2CO3, which is the most frequently used alkali performer. Additionally, in most concentrations the micro emulsion viscosities were lower. Thus, potassium carbonate might be an interesting candidate in future alkali applications.
To operate fields under in-situ combustion (ISC), the near-wellbore dynamics and far-field conditions have to be considered. In the near-wellbore region of vertical injection wells, the flow advancement of the combustion front is characterized by high velocities. Farther away from the injection wells, the advancement rate of the combustion front is much smaller. For a line drive configuration, the advancement of the front slows down from several meters per day near the wellbore to several centimeters per day in the far-field region.
To investigate the effects in the near-wellbore region and farfield conditions, laboratory experiments and simulations were performed and compared with the behavior of a Central European field produced by using ISC.
The laboratory experiments covered the kinetics in the near wellbore region as well as the far-field region by applying various heating rates and by preheating a kinetic cell before injecting air. The dynamic effects were investigated with a combustion tube. Mechanistic numerical simulation was based on the kinetics derived from the kinetic-cell experiments and applied to the combustion tube. The same set of conditions was then used to simulate the near-wellbore conditions in the Central European field and far-field conditions.
The results show that, in the near-wellbore region, the advancement of the combustion front is fast compared with heat conduction ahead of the front. Hence, low-temperature-oxidation (LTO) reactions and high-temperature-oxidation (HTO) reactions, as derived from the kinetic-cell experiments, are occurring in different distances from the injection well. In the far field, heat conduction ahead of the front and the flow of hot combustion gases preheat the reservoir before oxygen arriving at the combustion front. For these conditions, LTO and HTO reactions are occurring at the same location.
In the Central European field produced with ISC, the various operating conditions are shown at an example well. Four different phases of production can be seen: (1) oil production with cyclic steam stimulation (CSS), (2) shut-in of the well to stabilize the combustion front that is approaching, (3) oil-production response of the combustion front, and (4) conversion of the well for air injection. The air-injection rate is slowly increased to avoid too high temperatures in the early-injection phase (faster advancement of the heat front than heat conduction). The distance of the wells is approximately 70m to allow sufficient oil recovery per well and speed of the combustion front.
Phase experiments were performed to determine an Alkali Surfactant Polymer solution leading to low interfacial tensions for oil produced from the 16 TH reservoir of the Matzen field in Austria.
Core flood experiments with the ASP solution were conducted to investigate the incremental oil recovery. Experimental data was history matched utilizing numerical simulation.
Results show that at laboratory scale, the various chemicals travel at different speeds owing to the different retardation. Owing to the short distance travelled, the location of the various chemical fronts is close together. Hence, the conditions in the core floods resemble the conditions in the phase experiments.
At reservoir scale, however, even after only 0.2 Pore Volumes (PV) injected, a significant separation of the species is seen. Owing to the difference of the reservoir and core scale, chemical compositions need to be used which are leading to sufficient incremental oil for a wide range of compositions. The incremental oil production from ASP flooding can be substantially overestimated if the separation of the chemicals owing to retardation is not accounted for in the design of the chemical flood.
In case that pseudo components are used in reservoir simulation, the components should have similar retardation characteristics to ensure that incremental recovery is not overestimated.
The risk of economic failure of infill drilling campaigns increases with the increasing maturity of an oil field. The increased risk is due to the lower remaining movable oil in the late stages of a field's life compared to earlier phases. Despite the additional information owing to drilling of wells and production history, substantial geological and dynamic uncertainties remain. In this paper, an approach is presented for selecting an infill well portfolio of 10 wells from a total of 96 that explicitly accounts for these uncertainties.
The geological uncertainty can be exposed by generating a multitude of geological models conditioned to known log/correlation data. These models need to be classified and a subset of representative models extracted that in turn are calibrated (history matched) to past field performance and then used for forecasting. Calibration using a suitable ensemble of representative geological models aims to maintain geological diversity while reducing the error to historical data through an objective function.
Probabilistic Property Maps can then be generated to identify potential infill well locations. Probabilistic maps offer a major improvement compared to selection of infill well locations using a single geological realization. For mature assets, forecasting requires simulation of incremental oil recovery since infill wells represent incremental projects over a base case. Using an appropriate ensemble of models allows probabilistic representation of the incremental oil production and associated economics.
First, individual infill well performances are forecasted. Next, the individual infill well locations are evaluated taking the history matching error into account and using utility theory to cover the risk adverseness attitude of the company. Doing so enables selection of an infill well portfolio under uncertainty and leads to a selection of well locations carrying lower risk compared to a selection of locations neglecting history match error and/or disregarding the risk attitude of a company.
Chiotoroiu, Maria-Magdalena (OMV Exploration/Production Ltd) | Peisker, Joerg (OMV Exploration/Production Ltd) | Clemens, Torsten (OMV Exploration/Production Ltd) | Thiele, Marco (Streamsim Technologies, Inc.)
The polymer-pilot project performed in the 8 TH reservoir of the Matzen field showed encouraging incremental oil production. To improve further the understanding of recovery effects resulting from polymer injection, an extension of the pilot is planned by adding a second polymer injector. Forecasting of the incremental oil production needs to take the uncertainty of the geological models and dynamic parameters into account. We propose a work flow that is composed of a geological sensitivity and clustering step followed by a dynamic-calibration step for decreasing the objective function (OF) to improve the reliability of a probabilistic forecast of the incremental oil recovery. For the geological sensitivity, hundreds of geological realizations were generated by taking the uncertainty in the correlation of the sand and shale layers, logs, cores, and geological facies into account. The simulated tracer response was used as dissimilarity distance to classify the geological realizations. Clustering was then applied to select 70 representative realizations (centroids) from a total of 800 to use in the full-physics dynamic simulation. In the dynamic simulation, an OF composed of liquid rate and tracer concentration of the produced fluids was introduced. To improve the calibration further, the P50 value of incremental oil production as derived from simulation was compared with the incremental oil production determined from decline-curve analysis (DCA) from the wells surrounding the polymer-injection well. The mismatch between the P50 and the DCA was improved by adjusting polymer viscosity. The calibrated models were then used for both a probabilistic forecast of incremental oil caused by an additional polymer injector and an estimate of the expected polymer concentration at the producing wells.
Clemens, Torsten (OMV) | Kienberger, Gerhard (OMV) | Persaud, Mira (OMV) | Suri, Ajay (University of Petroleum and Energy Studies) | Sharma, Mukul M. (University of Texas at Austin) | Boschi, Marcelo (OMV) | Øverland, Alf M. (OMV)
Water injection is commonly used to improve oil recoveries in depleting reservoirs. However, insufficient injectivity can result in water-injection projects being limited in injection rates, which can sometimes make them uneconomic. Implementing water-injection projects requires a multidisciplinary approach to optimize water-injection rates for reservoir-performance, cost, and well-design considerations.
The costs for the surface facilities are dependent on the required water quality, water temperature, and other operating parameters that are linked to the injectivity of water. A work flow including quantitative assessment of the injectivity development as a function of the operating parameters as well as the uncertain geomechanical and reservoir parameters can be used to improve the surface-facility design.
Such a work flow was applied to a shallow offshore field. The results showed that the base-case design of the facilities should be modified to avoid an increase of the flowing bottomhole pressure (BHP) above the minimum stress of the caprock. The effect of the various parameters on the BHP was investigated, and the sensitivity of the BHP to uncertain input parameters under different operating conditions was tested. The results indicated that the BHP does not exceed the BHP limit, and hence the injectivity is expected to be high enough for a sufficiently long period of time under a wide range of conditions.
Polymer flooding of oil fields has not reached the same maturity as waterflooding. Hence, implementing polymer projects at field scale requires a workflow comprising several steps. The workflow starts with screening of the portfolio of an organization for oil fields potentially amenable for this enhanced-oil-recovery (EOR) method. Next, laboratory and field testing is required, followed by sector and field implementation and finally rollout in the portfolio.
Going through the workflow, not only is the subsurface uncertainty reduced, but also the knowledge regarding the cost structure and operating capabilities of the organization is improved.
Analyzing the economics of polymer-injection projects shows that costs can be split into costs dependent on the polymer injector/producer (polymer pattern) and costs that are independent. Knowing these costs, a minimum economic number of patterns (MENP) is defined to achieve net present value (NPV) of zero. This number is used to determine a minimum economic field size (MEFS) for polymer injection, which is taken into account in the screening of the portfolio.
A robustness criterion for economic-evaluation purposes is defined as the minimum number of patterns required for economic polymer injection. By use of this criterion, a diagram is derived allowing for screening of fields for polymer economics by use of pattern-dependent and pattern-independent costs and the utility factor (UF).
The cost structure reveals how the NPV of polymer projects changes with the number of patterns, incremental oil, and injectivity. Injectivity is particularly important because it determines the chemical-affected reservoir volume (CARV) or speed of production.
A sensitivity analysis of the NPV showed that for the cost structure used here, in addition to the polymer costs, the well costs are important for the economics of a full-field polymer-injection project.
The 8 TH reservoir is a "supermature" field which has been in production for more than 65 years. It was waterflooded for more than 50 years resulting in a current water cut of 96 %. The field contains medium viscous oil (in-situ viscosity 19 cP) and hence was considered for polymer injection despite the high water cut which was suggested by some authors to be challenging for polymer injection.
An inverted five spot unconfined polymer injection pilot was performed to reduce the subsurface uncertainties, determine if polymer flooding could lead to incremental oil in "supermature" fields, improve the operating and monitoring capabilities and improve the economic model for full-field implementation.
The results of the pilot show that an increase in 5- 10 % of the recovery factor can be achieved in the pilot area. The reasons for incremental oil production by polymer injection in this "supermature" field are acceleration along high permeable flow paths but more importantly substantial flow diversion in this heterogeneous reservoir. In the pilot area, the highest oil production since 1978 was achieved.
The main uncertainties related to surface handling of the polymer solution prior to injection, injectivity and incremental oil recovery could be reduced by monitoring of various parameters. In particular tracers and molecular weight distribution of polymers were measured to improve the understanding of the polymer solution effects on reservoir performance.
In addition, numerical simulations concerning injectivity and reservoir performance were performed to further improve the understanding of the processes and be able to optimize the operations. The simulations included polymer solution injection induced fractures as well as geological, reservoir fluid/relative permeability and polymer solution property uncertainties and allowed forecasting under uncertainty.
The cost structure of the polymer pilot was used to evaluate full-field economics taking learning curves, upscaling and costs optimisations into account.