Real-time analysis and data analytics have become cornerstones in reservoir management of waterflood operations or conformance program. Connectivity between injector-producer pairs and premature breakthrough of injected water or gas are perennial issues that can make or break the economics of secondary and tertiary recovery projects. In this study, we aim to harness the advances in modern data analytics and real-time analysis to systematically evaluate a suite of standard diagnostics tools and propose novel ones for improved recovery projects. Although the scope of these reservoir dynamics evaluation tools can be extensive, our current investigation utilizes data from the Permian Basin.
A suite of reservoir models under varying conditions involving water injection helped understand and evaluate a number of diagnostics tools and devise new characteristics plots. We performed over 8,000 model runs and used data analytics to assess these tools. These tools include water/oil ratio (WOR) vs. time plot, Chan diagnostics, reciprocal-productivity index (RPI) plot, gas/oil ratio (GOR) vs. time plot, among others. We investigated the well-spacing effect ranging from 20 to 320 acres, grid effects, and heterogeneity effects in evaluating these tools. We also explored heterogeneity measures, such as the Dykstra-Parsons method and an index based on final hydrocarbon pore-volume injection (HCPVI), and ultimate recovery. Both cluster analysis and
This study shows critical parameters for oil recovery under waterflooding are reservoir flow paths and connectivity between layers, reservoir storativity, fluid properties, the thickness of the oil/water transition zone, and fluid mobilities. We also observed that the water breakthrough time does not show a clear relationship with IRPI. Nonetheless, the HCPVI at breakthrough time exhibited a linear correlation with the ultimate oil recovery. In the absence of water production or the presence of water channeling a linear trend emerges for the final HCPVI plot. Cluster analysis and real-time production data analysis have demonstrated the strength of a new reservoir dynamics indicator plot of ultimate hydrocarbon recovery vs. initial reciprocal productivity index. Combination of this indicator and traditional diagnostics and heterogeneity index can quantify the spread of final recovery efficiently.
We present the first comprehensive experimental evaluation of CO2 EOR in organic rich shale. Experiments in preserved core demonstrated the potential of CO2 to extract the naturally occurring oil in organic rich shale reservoirs, whereas tests in re-saturated core plugs were used to compute accurate recovery factors, and evaluate the effect of soak time, operating pressure, and the relevance of slim-tube MMP on recovery. 18 core-flooding experiments were conducted in sidewall cores from different shale plays.
The cores re-saturated with crude oil, were first cleaned by Dean-Stark extraction, and submitted to porosity and compressibility determination. The re-saturation, confirmed by CT-scanning, was attained by aging the core plugs at high pressure for two to four months. In all experiments, glass beads surrounding core samples were used to simulate the proppant and physically recreate in the laboratory a hydraulic fracture connected to the shale matrix. The slim-tube MMP was measured with CO2, and core-flooding experiments were performed below, close to, and above the MMP. The displacement equipment was coupled to a medical CT-scanner that enabled us to track the changes in composition and saturation taking place within the shale cores during the experiments. Continuous CO2 injection and huff-and-puff were evaluated using soak time from zero to 22 hours. Fixed reservoir temperature was used in all the experiments.
Recovery factors ranged from 1.7 to 40%. The wide variation was the result of different experimental conditions for pressure and soak time. Both operational parameters were found to significantly affect the recovery. Increasing soak time at constant pressure consistently resulted in significant increase in recovery. The increase varied from 78 to 464% for different pressures and oil composition. Similarly, increasing operating pressure at constant soak time resulted in significant increase in recovery factor from 44 to 338% depending on soak time and oil composition. Unlike the typical response during CO2 EOR in conventional rocks, in organic rich shale, further pressure increases beyond the slim-tube MMP continued to increase the recovery factor significantly. In all runs, almost all oil recovery occurred within three days from the start of the experiment, and in all huff-and-puff tests the highest rate of recovery was observed in the first cycle, implying oil recovery with CO2 is a fast process, in comparison to oil re-saturation of the samples which occurs at a significantly slower rate.
This investigation demonstrates CO2 EOR is a technically feasible method to extract significant amounts of crude oil from organic rich shale reservoirs and it provides operational understanding of how to manage pressure and soak time to maximize recovery. The recovery factors obtained in this investigation, in the context of the vast reserves of crude oil contained in organic rich shale, can sustain a second shale revolution and further capitalize oilfield infrastructure.
This paper discusses a review and adaptation of some classic waterflood performance analytical methods, such as
These classic techniques account for the solution of the one-dimension frontal advance Buckley-Leverett theory (1942), assuming stable flow. In addition, the traditional semilog linear relationship between oil-water relative permeability ratio and water saturationis assumed (constant parameters
This work proposes to redefine aforementioned classic waterflood performance analytical methods with novel oil and water relative permeability expressions derived from the effective-fingering model(EFM) presented by
Adaptation of classic equations (stable) to solutions that account for unstable flow results in more reliable diagnostic-plot techniques for the case of viscous-oil, allowing to correct predictions of oil and water production in the case of heavy-oil waterflooding Additionally, new equations resulted in unified solutions that can be applied for both stable and unstable waterflood and help to improve reliability when estimating ultimate oil recovery, volumetric sweep efficiency, and various reservoir parameters. In the presence of viscous fingering, the water breakthrough and oil recovery from new
In its entirety, these novel waterflood performance analytical methods incorporate viscous fingering features in the traditional flow functions, encouraging the ability to predict ultimate oil recovery for both unstable and stable waterflooding cases and for chemical flooding (i.e., polymer with future adaptation) in heavy-oil reservoirs and facilitating the optimization of heavy-oil enhanced oil recovery (EOR) projects. These results might provide a basis to adapt other classic waterflood performance analytical methods.
Smart water and low salinity waterflooding has been established as an effective recovery method in carbonate reservoirs by demonstrating a significant incremental oil recoveries in secondary and tertiary modes compared to seawater injection. Therefore, understanding of multiphase flow phenomena in reservoir rocks is critical to optimize injected water formulations for substantial increase in oil recovery. Characterization of fluid-fluid and fluid-rock interactions have been extensively conducted at micro- and macroscopic scale, attempting to reveal the underlying mechanisms responsible for wettability alteration. Indeed, routine methods for assessing macro-wettability of fluids on rock surfaces (contact angle) include the sessile drop and captive bubble techniques. However, these two techniques can provide different contact angle depending on rock surface heterogeneities, roughness and drop size. Thus, contact angle measured at macroscale can only be used to characterize the average wettability and a direct visualization at nanoscale is needed to identify oil and brine distribution in the carbonate matrix and wettability state at the pore scale. The application of ion-beam milling techniques allows investigation of the porosity at the nanometer scale using scanning electron microscopy (SEM). Imaging of carbonate porosity by SEM of surfaces prepared by broad ion beam (BIB) and under cryogenic conditions allow to investigate preserved fluids inside the rock porosity and, combined with energy dispersive spectroscopy (EDS) identify crude oil and brine distributions and quantify carbonate-oil interfaces and wettability state. The experiments have been conducted on carbonate rock samples aged in crude oil and saturated with brines at high and reduced ionic strength. This study established an experimental protocol using Cryogenic high resolution broad ion beam (Cryo-BIB SEM) equipped with energy dispersive spectroscopy (EDS). The results show that ion-BIB milling provides a smooth surface area with large cross-section of few mm2. High resolution imaging analysis allowed identification of the different phases, chemical mapping and distribution of oil, brine within the porous matrix. Segmentation of rock-oil-brine interface allowed an estimation of the in-situ contact angle and showed the effect of injected salinity brine on the 2D contact angle and more accurate description of the carbonate wettability at nanoscale.
The objective of this research was to develop a model to predict the optimum phase behavior of chemical formulations for a given oil based on the molecular structure of the surfactants and co-solvents. The model is sufficiently accurate to provide a useful guide to an experimental testing program for the development of chemical EOR formulations. There are thousands of combinations of surfactants and co-solvents that could be tested for each oil, so even approximate predictions are very useful in terms of reducing the time and effort required for testing and for prioritizing the chemical combinations to test that are most likely to yield ultra-low IFT at reservoir conditions. The effects of changing molecular structures (e.g. swapping head groups, swapping hydrophobes, increasing the length of hydrophobes, increasing the number of PO and EO groups, adjusting the ratios of surfactants) are shown. The variables with the greatest impact on the optimum salinity and solubilization ratio were identified, and methods are proposed to shift the optimum salinity and the optimum solubilization ratios in any desired direction. The structure-property model was developed and tested using a large dataset consisting of 684 microemulsion phase behavior experiments using 24 oils. The chemical formulations used 85 surfactants and 18 co-solvents in various combinations. Both optimum salinity and optimum solubilization ratio (and thus IFT) are modeled whereas other models have focused almost exclusively on the optimum salinity. Predicting the optimum solubilization ratio is actually of more value because of its relationship to IFT. The models include the effects of co-solvent partitioning, soap formation and the molecular structure of both the surfactants and co-solvents.
In-situ upgrading (IU) is a promising method of improved viscous and heavy oil recovery. The IU process implies a reservoir heating up and exposition to temperature higher than 300°C for long enough time to promote a series of chemical reactions. The pyrolysis reactions produce lighter oleic and gaseous components while a solid residue remains underground. In this work, we developed a numerical model of IU based on lab experiences (kinetics measurements and core experiments) and validated results applying our model to an IU test published it the literature. Finally, we studied different operational conditions searching for energy-efficient configurations.
In this work, two types of IU experimental data are used from two vertical-tube experiments with Canadian bitumen cores (0.15 m and 0.69 m). A general IU numerical model for the different experimental setups has been developed and compared to experimental data, using a commercial reservoir simulator framework. This model is capable to represent the phase distribution of pseudo-components, the thermal decomposition reactions of bitumen fractions and the generation of gases and residue (solid) under the cracking conditions.
Simulation results for the cores submitted to 370°C and production pressure of 15 bar, have shown that oil production (per pseudo-component) and oil sample quality were well-predicted by the model. Some differences in gas production and total solid residue were observed with respect to laboratory measurements. Computer-assisted history matching was performed using an uncertainty analysis tool on the base of the most important model parameters. In order to better understand IU field-scale test results, the Shell’s Viking pilot (Peace River) was modeled and analyzed with proposed IU model. The appropriated grid-block size was determined and calculation time was reduced using the adaptive mesh refinement technique. The quality of products, the recovery efficiency and the energy expenses obtained with our model were in good agreement with the field test results. Also the conversion results (upgraded oil, gas and solid residue) from the experiments were compared to those obtained in the field test. Additional analysis was performed to identify energy efficient configurations and to understand the role of some key variables, e.g. heating period and rate, the production pressure, in the global IU upgrading performance. We discuss these results which illustrate and quantify the interplay between energy efficiency and productivity indicators.
This study investigates how compositional effects interact with the flow behavior during near miscible (and immiscible) CO2-oil displacements in heterogeneous systems. A series of numerical simulations modeling 1D slim-tube and 2D areal systems were performed using a fully compositional simulator. With negligible numerical dispersion, the fine-scale (Δx=0.005m) slim-tube simulations were performed to provide the "truth case" in terms of the compositional effects and oil/component recovery. A number of grid resolutions were tested to examine cell-size effects on the simulation accuracy. It was found that coarse cell size not only leads to spreading of the displacing front, but also lowers the displacement efficiency by reducing the component stripping effects, as noted by
To summarize, compositional effects can have a very significant impact on the prediction of near-miscible CO2 EOR projects. Issues such as front stability, local displacement efficiency and formation of fingering/channeling during CO2 near-miscible displacement can lead to behavior that is significantly different from immiscible flooding in these systems. The process of mass transfer between CO2 and oil can be hampered to a certain degree by unstable flow depending on the level of heterogeneity. This leads to a further reduction in component recovery, particularly of the heavier components. Lastly, the appropriate upscaling methods considering mass transfer still require further investigation for CO2 near-miscible displacement in field-scale applications. The complete dataset and results of this study are available online as a model case example for testing out potential upscaling techniques for compositional flows in heterogeneous systems (
Al-Rushaid, Mona (Kuwait Oil Company) | Al-Rashidi, Hamad (Kuwait Oil Company) | Ahmad, Munir (Kuwait Oil Company) | Azari, Mehdi (Halliburton) | Hadibeik, Hamid (Halliburton) | Kalawina, Mahmoud (Halliburton) | Hashmi, Gibran (Halliburton) | Hamza, Farrukh (Halliburton) | Ramakrishna, Sandeep (Halliburton)
Reservoir relative permeability and capillary pressure, as a function of saturation, is important for assessing reservoir hydrocarbon recovery, selecting the well completion method, and determining the production strategy because they are fundamental inputs to reservoir simulation for predicting lifetime production of a well. Estimation of relative permeability and capillary pressure curves at reservoir conditions is also an important task for successful planning of waterflooding and enhanced oil recovery. The relative permeability and capillary pressure data estimated from core analysis might cause concern regarding representativeness, and adjustments are typically necessary for successful production forecasting. This paper proposes a new method to obtain relative permeability and capillary pressure curves with downhole pressure-transient analysis (PTA) of mini-drillstem tests (miniDSTs) and well log-derived saturations.
The new approach was based on performing miniDSTs in the free water, oil, and oil-water transition zones. Analyses of the miniDST buildup tests provided absolute formation permeability, endpoints of relative permeability to both oil and water, and curvature of the relative permeability data. Additionally, resistivity, dielectric, and nuclear magnetic resonance (NMR) logs were used to determine irreducible water, residual oil, and transition zone saturations. Combining these downhole measurements provided the relative permeability and capillary pressure curves.
This paper presents numerical modeling of low tension surfactant gas based EOR method. In this process, slugs of various surfactant solutions and gas are alternated injected to mobilize remained oil left from water flood. The objective of this paper is to model the mechanisms behind the process by history matching the experimental data and simulation of a field-scale reservoir pilot. A four-phase chemical flooding reservoir simulator (UTCHEM) was used to history match a published core flood experiment and simulate a pilot-scale case. The results from the history match reveale that interfacial tension (IFT) reduction between oil and water by surfactant, displacement of oil by gas, and the mobility control of gas are the main mechanims lead to a substantioal increase in oil recovery. Based on these key findings, modeling of the low-tension surfactant-gas flood shows that such a process is very positive for low permeability reservoirs with a 90% oil recovery of the initial oil saturation (Sio=0.56) in a coreflood experiment and a range of recovery factors between 50% to 70% of the water flood in large scale cases.
Aamodt, G. (ConocoPhillips Skandinavia AS) | Abbas, S. (ConocoPhillips Co) | Arghir, D. V. (ConocoPhillips Skandinavia AS) | Frazer, L. C. (ConocoPhillips Co) | Mueller, D. T. (ConocoPhillips Co) | Pettersen, P. (ConocoPhillips Skandinavia AS) | Prosvirnov, M. (ConocoPhillips Skandinavia AS) | Smith, D. D. (ConocoPhillips Co) | Jespersen, T. (Halliburton Co.) | Mebratu, A. A. (Halliburton Co.)
This paper discusses a field case review of the processes used to identify, characterize, design and execute a solution for a waterflood conformance problem in the Ekofisk Field that developed in late 2012. The Ekofisk Field is a highly-fractured Maastrichtian chalk reservoir located in the Norwegian sector of the North Sea. Large scale water injection in the field began in 1987 and overall the field has responded well to waterflood operations. However, fault reactivation coupled with extensive natural fractures and rock dissolution has resulted in some challenging conformance issues. In late 2014, a solution was executed to control this problem. Details of the diagnostic efforts and how this data was used to identify, characterize and mitigate an injector/producer connection through a void space conduit (VSC) will be outlined and discussed. These diagnostics include pressure transient analysis (PTA), interwell tracers, injection profiles, seismic mapping, fluid rate analysis, fluid composition and temperature monitoring. The importance of this data analysis is the key element necessary to select an effective solution.
The selected approach involved pumping a large tapered nitrified cement treatment into the offending injector, which is believed to be the single largest nitrified cement operation ever pumped within the oil industry. Because of extremely rapid communication with an offset producer, a protective gel was used to reduce the risk of cement entry into that producer. A brief review of alternative mitigation options and the reasons for selecting the nitrified cement treatment will be discussed. Additionally, a complete review of the shutoff technique, product, damage mitigation strategy, and complications associated with timing and coordination in an offshore environment will also be discussed. Finally, a summary of lessons learned, job execution observations, post-treatment performance results over the past three years, and forward plans will be presented. Based on these results it is believed that there are a number of opportunities to add strong value through conformance engineering.