IOR 2015 - 18th European Symposium on Improved Oil Recovery

This paper presents a field case study of conformance engineering efforts completed in the West Sak field throughout the past eight years. The West Sak field is a shallow viscous oil reservoir with poorly consolidated sand that has been under waterflood since 1998. Because of the nature of the formation and the completion techniques used, the field has experienced some severe conformance issues. Conformance candidate identification and selection criteria are reviewed followed by an overview of additional problem characterization efforts. A variety of solution designs considered and attempted are discussed with a summary of lessons learned from both failures and successes during this effort. This review discusses treatments that range from pumping graded CaCO3, molten wax, special cement blends, and, finally, preformed particle gels (PPGs) or water swelling polymer (WSP) crystals. A majority of these treatments were executed on horizontal wells, which required adjustments for some challenging placement control dynamics. A review of the efforts to control those placement dynamics is presented, discussing some potential problems associated with that control. The principle objective of this work was the elimination of open channels connecting water injection wells with oil producers. This connection eliminated matrix flow between the wells and threatened secondary recovery potential. Ultimately, the evolution of current solution treatments is provided with a brief benefit summary of the overall performance of this effort.

In this paper we describe the design of a CO2 foam pilot in the Salt Creek Light Oil Unit in Natrona County, WY. CO2 foam technology was chosen as a promising candidate to improve sweep efficiency in certain target patterns. The second Wall Creek (WC2) sandstone formation is the primary producing interval, with a net thickness of about 80 feet and at a depth of approximately 2,200 feet. The first screening step towards identifying a pilot area involved a detailed study of the geologic features, injection-production characteristics, and operational aspects of numerous patterns in the field. An injector centered five-spot pattern was selected for the pilot. A surfactant formulation was developed that provided the desired foam response at reservoir conditions, and also met preliminary economic and operational expectations. The foam characteristics of the surfactant were further investigated by performing core-flood experiments. A history matched reservoir simulation model was developed to forecast the performance of the field in the absence of foam and thus provide a baseline to compare with the anticipated foam response. The model was later calibrated with foam performance data and used to guide the implementation of the pilot and to forecast field performance. The pilot was initiated in September 2013. Initial results are discussed.

The gas injection IOR project for the basalt reservoir started in April 2014 in Yurihara oil field, Japan. In this reservoir, water cut increase in the borehole at the structurally high level had been observed. This was interpreted as a phenomenon relating to the characteristics of the inhomogeneous basalt reservoir. It was difficult to explain these using the previous reservoir model based on the simple geological concept, in which the lithofacies distribution was drawn into a single concentric circle form whose center corresponds to the crater area of a volcano. In order to improve the history match of the reservoir simulation, the new geological study started and the geological model was revised overall. In this concept, multiple volcanic craters are located dispersively in this field. Then, the reservoir model was renovated by multi-point geostatistical approach utilizing the geological training image. In facies modeling, the basalt was classified in three types, which are sheet flow, pillow lava and hyaloclastite. Since the most productive zone seems to be pillow lava, the production wells have been completed in the zone, where the pillow lava were dominantly observed in well logging. The problem here is that the productivity is much different in the pillow lava. In other words, the content of pillow is not proportional to productivity. Consequently, we needed to set the much variation of permeability in the pillow facies. So, the permeability distribution was estimated by Gaussian simulation, where we added the seismic attribute as soft data. Then, the distribution was modified by gradual deformation method, where the objective function was calculated using the residual error with the observation and the simulated value of bottom-hole pressure and the water cut. A several realizations matching to production history were extracted, and are currently utilized to gas injection optimization. Not only that, but also the prediction for the optimal timing of starting WAG is required.

CO2 foam EOR technology is being evaluated in mature oil fields for improving CO2 flood volumetric sweep efficiency. Since the residual oil saturation to supercritical CO2 flood is quite low (typically 5%-10% under ideal sweep conditions), an improvement in volumetric sweep can lead to substantial improvements in oil recovery. The success of a CO2 foam EOR project depends heavily on the choice of the chemical formulation and the injection strategy implemented in the field. In this paper we present our framework for design and implementation of CO2 foam EOR technology in oil fields - including chemical formulation development, laboratory core flood experiments to characterize foam performance and engineering of the chemical injection process in the field, which has demonstrated efficient field implementation while optimizing the use of lab and computational resources and reservoir samples. Key factors for consideration in developing a chemical formulation for CO2 foam EOR process are low adsorption on reservoir rock, sufficient CO2-water foam stability, and efficient transport in CO2 and brine at reservoir conditions. In addition the chemical formulation should have no adverse effects on field operations, the environment, health or safety. A wide gamut of potential chemical formulations are evaluated using a set of well-defined high-throughput screening experiments. Experimental results are then statistically analyzed and ranked via pre-defined figure of merit. To conserve scarce reservoir core plugs, core-flooding experiments are initially conducted on model cores to select the optimal formulation. Data is then collected from additional core-flooding experiments using core plugs from the target reservoir to characterize foaming behavior of the chemical formulation as a function of shear rate, formulation concentration, foam quality and oil saturation following a detailed experimental design. This laboratory data is then used to develop an empirical foam model for use in a reservoir simulator. Reservoir simulation cases are run to develop an optimal strategy for injecting the chemical formulation. The reservoir model is validated with field data and is further used to guide the implementation of the CO2 foam EOR process. This design and implementation framework is illustrated with relevant examples.

Sea water (SW) with sulphate as one of the active ions, has been reported to alter the wettability of outcrop chalk to more water-wet. Reservoir chalk samples contain higher sulphate concentration than found to affect the wettability of outcrop chalk. The main objectives for the study were to determine the effect of the initial sulphate in reservoir chalk on the spontaneous imbibition of SW and how representative wettability conditions can be established. Reservoir chalk with and without initial sulphate were prepared using synthetic formation water without sulphate and with sulphate concentration as in real formation water. The spontaneous imbibition of SW was faster and higher for the reservoir rock with initial sulphate than for the rock without initial sulphate. This means that the initial sulphate made the reservoir chalk more water-wet. Reservoir chalk should be prepared with the same initial sulphate concentration as in the reservoir area where the samples are taken. This is required to obtain correct potential estimates for water flooding and enhanced oil recovery methods. The amount of sulphate in the original reservoir chalk and in the chalk after restoration should be determined by analysis of effluent samples during cleaning and restoration of core plugs.

Originally, chalk reservoirs were waterflooded for pressure support; maintaining the pressure above the bubble point of the oil, and also preventing the compaction of the rock caused by the pressure depletion. Seawater waterflooding into a chalk reservoir in the North Sea proved to be a success not only by maintaining pressure and reducing compaction, but additionally the oil recovery rate soon increased. Intensive research during the last decade has proven that seawater at high temperatures acts as a “Smart Water” being able to improve the water wetness of carbonates. The reason for that are the chemical interactions happening in the reservoir between the oil, rock and injection water, disturbing the established chemical equilibrium and leaving the rock surface a little more water-wet. The increased water wetness generates positive capillary forces, and the microscopic sweep efficiency is increased. Recent research has shown that seawater can even be modified to improve the oil recovery in a spontaneous imbibition process by 10% compared to the recovery using ordinary seawater. The seawater composition has to be tailored for every specific reservoir system, and especially important parameters to consider, when deciding on the composition of the injected seawater, are the mineralogy of the reservoir rock, and the temperature of the reservoir. For high temperature chalk fields > 100 °C, like Ekofisk (130 °C), seawater depleted in NaCl should be used as the “Smart Water” EOR fluid. For lower temperature reservoirs, <100 °C, like Valhall (90 °C), either seawater spiked with sulfate or seawater depleted in NaCl and spiked with sulfate should be used as the “Smart Water” EOR fluid. In this study, the objective was to optimize the seawater-based “Smart Water” composition for injection into chalk/carbonate. The optimal amount of NaCl present in seawater was investigated at 90 °C. The experimental results showed that more than 90% of the NaCl needed to be removed from seawater in order to increase the oil recovery significantly, compared to the recovery using ordinary seawater. By doing so, the oil recovery increased by approximately 8% OOIP.

Low salinity water injection (LSWI) is considered as a promising technique for improving oil recovery. Several mechanisms have been proposed for improving oil recovery by LSWI mainly based on core flood experiments, but these experiments are difficult to interpret and many conflicting results have been reported in the literature. While much attention has been paid to the role of rock mineralogy, important fluid/fluid interactions have been overlooked. A few attempts for identifying the significance of oil characteristics have been reported in the literature but the results have been inconclusive. Using our state-of-the-art flow visualisation and fluid/fluid characterisation capabilities, we have recently reported a physical phenomenon taking place when low salinity brine comes in contact with a crude oil, which revealed spontaneous formation of micro-dispersions of water in oil (SPE 166435 and SPE 169081). The micro-dispersions are associated with indigenous surface active components of crude oil. Migration of low salinity water into crude oils is also associated with perturbation of indigenous surface active materials, which can in turn modify the wettability of the system. Here in the current work, we aimed to quantitatively evaluate whether micro-dispersion formation plays a dominant role in the mechanisms by which LSWI may lead to improved oil recovery. A number of coreflood experiments have been designed and performed in which the propensity of different crude oils to form micro-dispersions was determined. In a specially designed mixing cell, low salinity brine was contacted with crude oils and the resultant micro-dispersions were remove prior to coreflood tests. Using pre-contacted and unadulterated crude oils, the performance of tertiary LSWI was examined. The results demonstrate the impact of mutual interactions between the aqueous and oleic phases. The results clearly shows that the amount of oil recovered by LSWI for the two cases varies significantly which indicate that the observed micro-dispersions play a crucial role in the performance of both high and low salinity water floods. Removing the micro-dispersions influences the wetting characteristics of cores through the association of the micro-dispersions with natural surface active components of crude oil. The results show that depriving crude oil from these compounds results in more water wet behaviour, which is in line with general consensus about how LSWI would change the wettability.

Abstract Oil recovery during CO2 injection into a thick and/or fractured reservoir will be limited as a result of viscous fingering and gravity override. Due to density differences between the injected CO2 and resident fluids in the reservoir, the CO2, being lighter, tends to rise to the top of the reservoir thereby bypassing some of the remaining oil. In order to study the impact of reservoir heterogeneity on oil recovery by seawater and CO2 flooding, this paper, for the first time, investigates the use of a dual core flooding apparatus to investigate the effect of both CO2 gravity override and permeability contrast on oil recovery performance by CO2 injection. Experimental investigation of different oil recovery schemes, including secondary and tertiary oil recovery processes, was conducted using dual core holders with different permeable carbonate composite stacks. The core holders were placed in parallel horizontally and contained a high permeable core plug (HPCP) and low permeable core plug (LPCP). The permeability ratio of HPCP to LPCP was 50 to 1 with the HPCP core holder placed above the LPCP core holder. Core flooding experiment was conducted at reservoir conditions with live reservoir fluids at a pore pressure of 3200 psi, temperature of 102oC and confining pressure of 4500 psi. Using this experimental setup, various experiments were conducted to determine the oil recovery performance as a function of injection rates, seawater/CO2 injection modes, slug volume, and diversion of CO2 by plugging the HPCP. Experimental procedures are provided for conducting these experiments that has the potential to become a gold standard for such studies. Results based on this study have shown that CO2 injection following waterflooding resulted in additional oil recovery, as expected. However, the amount of this recovered additional oil was dependent on initial core plug permeability, injection mode and CO2/seawater slug volume. It was observed that waterflooding recovered more oil from high permeable core plugs, compared to the tighter core plug. On average, seawater left considerable more remaining oil in LPCP, which indicated the poor performance of waterflooding in formations with high permeability contrast. The remaining oil in the LPCP was mobilized by plugging the HPCP using a diversion technique and a subsequent CO2 flood. This paper provides detailed description of the effect of different mechanisms of flooding with seawater and supercritical CO2 on recovering this additional oil from LPCP. The results bode well for CO2-EOR projects and will lead to further oil recovery potential beyond the normal CO2 flood.

Rheological behavior of nanofluids and their application in emulsion inversion D. Slavova, S. Pollak, M. Petermann Chair of Particle Technology, Ruhr-University Bochum The most common problem in crude oil production is the formation of water-in-oil (W/O) emulsions in reservoir rocks, which leads to an increase of viscosity compared to the oil itself. These types of emulsions are produced due to the simultaneous flow of oil and produced water, which increase the interfacial area of the oil and water phases. Chemical additives with functional groups such as naphthenic acids in oil form viscoelastic films at these surfaces resulting in stable water-in-oil (W/O) emulsions. By inducing a phase inversion into oil-in-water (O/W) emulsions, the viscosity can be reduced. Nanotechnology is an advanced technology that has proved its potential to cause phase inversion and to enhance oil recovery. The aim of this study is to investigate the effect of nanoparticles on the properties of emulsions. The use of new type of fluids called “nanofluid” has become an attractive tool to achieve emulsion inversion. However it is crucial to have a clear depiction of parameters that may influences the displacement process. Hydrophilic nanoparticles with single particle diameter range around 25 nm were employed and have been characterized under scanning electron microscope (SEM). The nanofluids are synthesized by the dispersion of different concentrations of nanoparticles Nanoclay to low salinity brines. The viscosity and density of the nanofluids have been investigated both as a function of nanoparticles concentration as well as temperature between 40°C and 80°C. As expected it was found, that the viscosity is increasing with the concentration of nanoparticles and decreasing with higher temperatures. In addition it could be demonstrated that the flow behavior of such nanofluids is strongly non-Newtonian in the range of the investigated shear rates from 100s-1. In addition to the investigation of the nanofluids, the phase inversion of different emulsions using these fluids was investigated. As model systems emulsions were formed with water, paraffin oil and different concentrations of naphthenic acid as surfactant. These emulsions were mixed with nanofluids of different viscosities and therefore different nanoparticle concentrations. The phase behavior and the viscosity of such mixtures was investigates in the range from 40°C and 80°C. The results clearly demonstrate that phase inversion could be achieved and that low viscous oil-in-water emulsions could be formed and therefore the high potential for EOR is illustrated.

In a polymer flooding process, the volume of polymer adsorbed in porous media directly affects the rate of polymer propagation through a reservoir, oil recovery and total cost. Polymer retention is an important factor that should be estimated before field application. A review of the polymer retention in literature reveals that polymer adsorption is strongly dependent on surface wettability. The retention of polymers on oil-wet surfaces may differ significantly from their retention on water-wet surfaces. Moreover, the retention of polymers on oil-wet surfaces is minimized while the adsorption of cationic polymers is still significant on such a surface. Although many reservoir rocks are mixed-wet, usually one adsorption isotherm curve is used for both water-wet and oil-wet fraction of rock. In some polymers there is a noticeable relationship between wettability and polymer retention which may affect the calculations significantly. On the other hand, the residual water saturation of porous media directly affects the distribution of wettability in mixed wet rocks and consequently the polymer retention volume. In this study, a 3-D pore-scale network model has been developed for a typical mixed-wet sandstone rock. The porosity and permeability data reported in literature for Bentheimer sandstone and reservoir rocks are used for model verification. The developed pore network was used to simulate the polymer flooding at different parts of reservoir above the OWC. For the same polymer (cationic or anionic), different experimental adsorption isotherms has been used in water-wet and oil-wet portions of reservoir. The results of pore network simulation were used to calculate the polymer retention in simulated volume. The volume of adsorbed polymer calculated by this method has been compared with the estimation that neglects wettability variation. The results show that there is a big difference in retention estimation if the wettability change is not taken into account. By assuming constant wettability (oil-wet or water-wet) throughout the reservoir, polymer retention is dependent only on polymer concentration and the predicted polymer retention is underestimated or overestimated.