Demulsification is the breaking of a crude oil emulsion into oil and water phases. A fast rate of separation, a low value of residual water in the crude oil, and a low value of oil in the disposal water are obviously desirable. Produced oil generally has to meet company and pipeline specifications. For example, the oil shipped from wet-crude handling facilities must not contain more than 0.2% basic sediment and water (BS&W) and 10 pounds of salt per thousand barrels of crude oil. This standard depends on company and pipeline specifications. The salt is insoluble in oil and associated with residual water in the treated crude. Low BS&W and salt content is required to reduce corrosion and deposition of salts. The primary concern in refineries is to remove inorganic salts from the crude oil before they cause corrosion or other detrimental effects in refinery equipment. The salts are removed by washing or desalting the crude oil with relatively fresh water. This stability arises from the formation of interfacial films that encapsulate the water droplets. To separate this emulsion into oil and water, the interfacial film must be destroyed and the droplets made to coalesce.
Although conformance-improvement gel treatments have existed for a number of decades, their widespread use has only begun to emerge. Early oilfield gels tended to be stable and function well during testing and evaluation in the laboratory, but failed to be stable and to function downhole as intended because they lacked robust chemistries. Also, because of a lack of modern technology, many reservoir and flooding conformance problems were not understood, correctly depicted, or properly diagnosed. In addition, numerous individuals and organizations tended to make excessive claims about what early oilfield gel technologies could and would do. The success rate of these gel treatments was low and conducting such treatments was considered high risk. As a result, conformance-improvement gel technologies developed a somewhat bad reputation in the industry. Only recently has this reputation begun to improve. The information presented in this chapter can help petroleum engineers evaluate oilfield conformance gels and their field application on the basis of well-founded-scientific, sound-engineering, and field-performance merits.
This page provides a brief review of illustrative field applications of polymer waterflooding as reported in the literature. In 1983, Manning et al. published a comprehensive and classic summary of the field results and performance of more than 250 polymer waterflooding projects and provided information relating to the early field applications of polymer waterflooding. Figure 1 shows the incremental oil production response for the North Burbank polymer flood. A polymer waterflooding project that involved a large full-field flooding project at the North Oregon Basin field in Wyoming's mature Big Horn Basin oil-producing area was reported in 1986 to be producing 2,550 BOPD of incremental oil production. It was reported that this polymer flooding project would recover ultimately more than 10 million bbl of incremental reserves from the mature North Oregon Basin field. The field project involved the flooding of both a fractured carbonate formation and a fractured sandstone formation with a polymer flood using partially hydrolyzed polyacrylamide(HPAM).
Application of horizontal wells and multi-stage fracturing has enabled oil recovery from extremely low permeability shale oil reservoirs, but the expected ultimate recovery (EUR) due to depressurization is only 5-10% of the original oil in place (OOIP). The objective of this work is to test whether coupling a chemical treatment with CO2 huff-n-puff can improve the oil recovery. The chemical blend (CB) contained an anionic surfactant and a persulfate compound in brine. Oil recovery efficiency of the CO2 with the chemical blend was compared with CO2 Huff-n-Puff cycles at different pressures (5200 psi, 4000 psi and 2800 psi). Outcrop Eagle Ford and Mancos core plugs were used in the study. This work shows that CO2 huff-n-puff is an efficient technique to improve oil recovery from oil shales. Most of the added oil was recovered in all the experiments. The pressure to which the cores were pressurized with CO2 did not affect the oil recovery significantly as long as it was high enough (2800 psi in these experiments). The addition of chemical blend seemed to impede the oil recovery. Because of the heterogeneity in shale samples, more experiments need to be conducted to understand and validate these conclusions.
Shale oil contributes more than 60% of the US oil production according to EIA (2019). Shale oil production has been feasible because of technological development for horizontal wells with multi-stage hydraulic fracturing. The hydraulic fracturing technique has improved significantly in recent years, but the estimated oil production in these unconventional reservoirs is less than 10%. For an average well, the oil production rates fall sharply in the first year (more than 75%) because of the extremely low permeability, microfracture closure, and large flow resistance at the matrix-fracture interface. To keep the sustainability of oil production from shale oil, it is essential to develop enhance oil recovery (EOR) techniques for unconventional reservoirs. There have been several investigations on surfactant-based treatments, water injection and CO2 huff-n-puff for shale EOR.
We studied the Vaca Muerta (VM) Play (Neuquén Basin, Argentina) focusing on an oil window mature well (VR ~0.9-1.1%) to determine 1) zones of enrichment and depletion, 2) correlation/allocation to produced fluids, and 3) in-situ GOR and PVT characteristics.
Zones of saturation versus depletion, total in-place liquids, oil quality and bitumen enrichment throughout the Upper (U-), Middle (M-), and Lower (L-) VM were documented using screening methods such as Rock-Eval, TOC, thermovaporisation and pyrolysis gas chromatography on 24 original whole rock samples as well as solvent extracted aliquots. For production allocation and API prediction produced fluids were analysed in comparison to extracts from the shale units using whole oil chromatography and stable carbon isotope as well as high resolution mass spectrometry (FT-ICR MS). For prediction of GOR and PVT characteristics a combination of MSSV-pyrolysis and PVT modelling was used in the PhaseKinetics approach (di Primio and Horsfield, 2006) for immature samples and in the PhaseSnapShot approach (Kuske et al., 2019) for matured samples.
Especially the methods and experimental protocols used for the predictive assessments (FT-ICR MS; MSSV) are novel, unique, and strongly improve our ability to correctly describe the effects of production fractionation on bulk fluid properties and hence to formulate appropriate production strategies. In general, this study excels by combining results from organic geochemistry with those of PVT modeling and analysis.
Gaol, Calvin (Clausthal University of Technology) | Wegner, Jonas (Clausthal University of Technology) | Ganzer, Leonhard (Clausthal University of Technology) | Dopffel, Nicole (BASF SE) | Koegler, Felix (Wintershall Holding GmbH) | Borovina, Ante (Wintershall Holding GmbH) | Alkan, Hakan (Wintershall Holding GmbH)
Utilisation of microorganisms as an enhanced oil recovery (EOR) method has attracted much attention in recent years because it is a low-cost and environmentally friendly technology. However, the pore-scale mechanisms involved in MEOR that contribute to an additional oil recovery are not fully understood so far. This work aims to investigate the MEOR mechanisms using microfluidic technology, among others bioplugging and changes in fluid mobilities. Further, the contribution of these mechanisms to additional oil recovery was quantified.
A novel experimental setup that enables investigation of MEOR in micromodels under elevated pressure, reservoir temperature and anaerobic and sterile conditions was developed. Initially, single-phase experiments were performed with fluids from a German high-salinity oil field selected for a potential MEOR application: Brine containing bacteria and nutrients was injected into the micromodel. During ten days of static incubation, bacterial cells and in-situ gas production were visualised and quantified by using an image processing algorithm. After that, injection of tracer particles and particle image velocimetry were performed to evaluate flow diversion in the micromodel due to bioplugging. Differential and absolute pressures were measured throughout the experiments. Further, two-phase flooding experiments were performed in oil wet and water wet micromodels to investigate the effect of in-situ microbial growth on oil recovery.
In-situ bacteria growth was observed in the micromodel for both single and two-phase flooding experiments. During the injection, cells were partly transported through the micromodel but also remained attached to the model surface. The increase in differential pressure confirmed these microscopic observations of bioplugging. Also, the resulting permeability reduction factor correlated with calculations based on the Kozeny-Carman approach using the total number of bacteria attached. The flow diversion of the tracer particles and the differences in velocity field also confirmed that bioplugging occurred in the micromodel may lead to an improved conformance control. Oil viscosity reduction due to gas dissolution as well as changes in the wettability were also identified to contribute on the incremental oil. Two-phase flow experiments in a newly designed heterogeneous micromodel showed a significant effect of bioplugging and improved the macroscopic conformance of oil displacement process.
This work gives new insights into the pore-scale mechanisms of MEOR processes in porous media. The new experimental microfluidic setup enables the investigation of these mechanisms under defined reservoir conditions, i.e., elevated pressure, reservoir temperature and anaerobic conditions.
Schumi, Bettina (OMV E&P) | Clemens, Torsten (OMV E&P) | Wegner, Jonas (HOT Microfluidics) | Ganzer, Leonhard (Clausthal University of Technology) | Kaiser, Anton (Clariant) | Hincapie, Rafael E. (OMV E&P) | Leitenmüller, Verena (Montan University Leoben)
Chemical Enhanced Oil Recovery leads to substantial incremental costs over waterflooding of oil reservoirs. Reservoirs containing oil with a high Total Acid Number (TAN) could be produced by injection of alkali. Alkali might lead to generation of soaps and emulsify the oil. However, the generated emulsions are not always stable.
Phase experiments are used to determine the initial amount of emulsions generated and their stability if measured over time. Based on the phase experiments, the minimum concentration of alkali can be determined and the concentration of alkali above which no significant increase in formation of initial emulsions is observed.
Micro-model experiments are performed to investigate the effects on pore scale. For injection of alkali into high TAN number oils, mobilization of residual oil after waterflooding is seen. The oil mobilization is due to breaking-up of oil ganglia or movement of elongated ganglia through the porous medium. As the oil is depleting in surface active components, residual oil saturation is left behind either as isolated ganglia or in down-gradient of grains.
Simultaneous injection of alkali and polymers leads to higher incremental oil production in the micro-models owing to larger pressure drops over the oil ganglia and more effective mobilization accordingly.
Core flood tests confirm the micro-model experiments and additional data are derived from these tests. Alkali co-solvent polymer injection leads to the highest incremental oil recovery of the chemical agents which is difficult to differentiate in micro-model experiments. The polymer adsorption is substantially reduced if alkali is injected with polymers compared with polymer injection only. The reason is the effect of the pH on the polymers. As in the micro-models, the incremental oil recovery is also higher for alkali polymer injection than with alkali injection only.
To evaluate the incremental operating costs of the chemical agents, Equivalent Utility Factors (EqUF) are calculated. The EqUF takes the costs of the various chemicals into account. The lowest EqUF and hence lowest chemical incremental OPEX are incurred by injection of Na2CO3, however, the highest incremental recovery factor is seen with alkali co-solvent polymer injection. It should be noted that the incremental oil recovery owing to macroscopic sweep efficiency improvement by polymer needs to be taken into account to assess the efficiency of the chemical agents.
Two upscaling exercises performed in 2013-14 and 2017-18 on two onshore green fields with conventional to viscous oil are presented, for which the upscaling tried to compensate the effects of grid coarsening, in particular the increase of numerical dispersion and the decrease of heterogeneity. Our methodology was to adjust the water/oil relative permeabilities called pseudo KRs in the coarse scale simulation, in order to reproduce the behavior in terms of pressure, rates, saturations and concentrations of the fine scale model, which was using microscopic rock KRs based on laboratory data.
As the upscaling depends on the fluid injected, it was done separately for waterflood and polymer flood. When done with polymer flood, the concentration of polymer had to be history matched also mainly by adjusting the Todd-Longstaff mixing parameter in addition to the KRs. As upscaling is case dependent, it was performed on several geological models, varying heterogeneity and grid size, but also rock KRs and even precocity of the polymer flood after some waterflood, to test the robustness of the approach.
It was found that pseudo-KRs for waterflood could be slightly degraded for viscous oils, whereas the upscaling was more neutral for conventional oils. This correlates well with field observation for viscous oils, where water production occurs generally a bit quicker than what numerical simulation predicts when using rock KRs, in absence of upscaling.
For polymer floods, which were considered in secondary or early tertiary mode, pseudo KRs were generally improved, mainly because the polymer steepened the saturation fronts, which can be well represented only with small lateral grid size.
The result of both upscaling exercises was that the increment of polymer flood versus waterflood was noticeably higher when computed on high resolution modelling. This is equivalent to saying that when using pseudo KRs resulting from this high resolution matching, the polymer increment on coarse grid is significantly higher than if computed without pseudo KRs. This improves the economic evaluation of the project, increasing the willingness to de-risk and implement early polymer floods on these fields.
The field-scale design of chemical enhanced oil recovery (cEOR) processes requires running complex numerical models that are computationally demanding. This paper provides an efficient screening platform for the cEOR feasibility study by presenting five artificial neural network (ANN) based models. We constructed 1,100 ANN training cases using CMG-STARS to capture the variation in reservoir petrophysical properties and the range of injected chemicals properties for a five-spot pattern. The design parameters were coupled with the reservoir properties using several functional links to optimize the ANN models and improve their performances. The training cases were employed using back-propagation methods to construct one forward model (Model #1) and four inverse models. Model #1 predicts reservoir response (i.e., oil rate, water cut, injector bottomhole pressure, cumulative oil) for known reservoir characteristics (i.e., permeability, thickness, residual oil saturation, chemical adsorption) and project design parameters (i.e., pattern size, chemical slug size and concentration), Model #2 predicts reservoir characteristics by history matching the reservoir response, and Model #3 predicts project design parameters for known reservoir response and characteristics. Models #4 and #5 predict project design parameters for a targeted cumulative oil volume and project duration time, which is useful for economical evaluation before the implementation of cEOR projects.
The validation results show that the developed ANN-based models closely predict the numerical results. In addition, the models are able to reduce the computational time by four orders of magnitude, which is significant considering the complexity of cEOR modeling and the need for reliable and efficient tools in building cEOR feasibility studies. In terms of accuracy, Model #1 has a prediction error of 5% whereas the error for other four inverse ANN models is about 20–40%. To enhance the performance of the inverse ANN models, we changed the ANN structure, increased training cases, and used functional links, which slightly reduced the error. Further, we introduced a back-check loop that uses the predicted parameters from the inverse ANN models as inputs in the forward ANN model. A comparison of back-check results for the reservoir response with the numerical results delivers a relatively small error of 10%, revealing the non-uniqueness of solutions obtained from the inverse ANN models.
Zhang, Ke (State Key Laboratory of Enhanced Oil Recovery, PetroChina Research Institute of Petroleum Exploration & Development) | Li, Shi (State Key Laboratory of Enhanced Oil Recovery, PetroChina Research Institute of Petroleum Exploration & Development) | Zhang, Shaojie (Department of Petroleum Engineering, University of North Dakota) | Pu, Hui (Department of Petroleum Engineering, University of North Dakota) | Wu, Xidao (China University of Petroleum)
The success of large-scale chemical enhanced oil recovery (EOR) such as polymer flooding and Alkaline-Surfactant-Polymer (ASP) flooding in Daqing Oilfield plays an important role in sustaining the stable high oil production rate in Daqing. In 2014, Daqing Oilfield officially implemented commercial-scale ASP flooding. It has successively conducted ASP flooding in sixteen areas. The annual crude oil production by chemical EOR in Daqing Oilfield in 2017 was almost 86 million barrels, marking the sixteenth consecutive years of more than 73.3 million barrels (~10million metric tons) of oil per year. ASP flooding produced more than 29.3 million barrels of oil in Daqing in 2018. Much experience and lessons have been learned on large-scale ASP flooding including: major factors that influence the recovery and methods to increase the recovery; measures to obtain the best economic efficiency; and how to tackle the technical challenges in ASP flooding. This paper discusses the field practices during the past five years in Daqing, including crucial application strategies, optimized design of surface facilities, field results, methods to solve technical challenges of ASP flooding, strategies to reduce cost for commercial-scale ASP technology, and future development direction of ASP flooding.