Yuan, Chengdong (Southwest Petroleum University) | Pu, Wanfen (Kazan Federal University) | Varfolomeev, Mikhail A. (Southwest Petroleum University) | Wei, Junnan (Kazan Federal University) | Zhao, Shuai (Southwest Petroleum University) | Cao, Li-Na (Kazan Federal University)
Conformance control treatment in high-temperature and ultra-high-salinity reservoirs for easing water/gas channeling through high-permeability zones has been a great challenge. In this work, we propose a deformable micro-gel that can be used at more than 100 °C and ultra-high salinity (TDS > 200000 mg/L, Ca2+ + Mg2+ > 10000 mg/L), and present a method for choosing the suitable particle size of micro-gel to achieve an optimal match with the pore throat of core.
First, the particle size distribution of micro-gel was analyzed to decide d50, d10 and d90 (diameter when cumulative frequency is 50%, 10% and 90%, respectively). Core flooding experiments were conducted under different permeability conditions from 20 to 900 mD. The migration and plugging patterns of the micro-gel were studied by analyzing and fitting injection pressure curves together with the change in the morphology of produced micro-gel analyzed by microscope. Finally, a quantitative matching relation was established between the size of micro-gel particles and the pore-throat size of core, its effectiveness was verified by evaluating plugging ability in subsequent water injection process.
The migration and plugging patterns were divided into three patterns: complete plugging, plugging – passing through in a deformation or broken state – deep migration, and inefficient plugging – smoothly passing through – stable flow. The second pattern can be further divided into three sub-patterns as strong plugging, general plugging and weak plugging. Based on the five patterns, a quantitative matching relation between the size of micro-gel particles and the pore-throat size of cores was established by defining three matching coefficients α=d10/d, β=d50/d, γ=d90/d (d is the average pore throat diameter). The effectiveness of this quantitative matching relation was verified by evaluating the plugging ability (residual resistance coefficient) in sequent water flooding process after the injection of 1.5 pore volume of micro-gel. For a strong permeability heterogeneity, the strong plugging is believed to be the expected pattern. The particles size and the pore-throat size should meet the following relationship: 1 < α < 2, 2 < β < 4, 4 < γ <6. In this scenario, the deformable micro-gel particles could achieve both an effective plugging and a deep migration. The quantitative matching relation can provide an indication for the quick determination of the suitable size of deformable micro-gel for conformance control processes in field application, including profile control and water-shut off treatment.
A new autonomous outflow control device is developed to choke back the injection fluid into natural/induced fractures and mitigate the disproportional injection of fluid into the thief zone and potentially creating short-circuit to the nearby producer wells. This paper will present an overview of the flow loop performance testing, and demonstrates the design consideration and integration with completion design and its benefit by reservoir modelling.
The bi-stable devices should be installed in several compartments in the wells and operate as normal outflow control valves initially. When the injected flowrate flowing through a bi-stable valve exceeds a designed threshold, the bi-stable valve will autonomously move to another position to choke back the injection of fluid at that specific compartment. This allows the denied fluid to be distributed among the valves installed at neighbouring compartments. This performance enables the operator to minimise the impacts of natural fractures on the injected fluid conformance and to control the growth of thermal fractures while improving the efficiency of the injection well systems.
The flow performance of the bi-stable valve has been validated and the flow behaviour can be simulated in the reservoir model. Static flow modelling has been used to establish the valve setting and packer placement in the well section and to demonstrate an improved distribution of the water injection and the effect of restricting water to the thief zone on the nearby producer oil recovery.
A reservoir modelling method has been established to evaluate the bi-stable device performance in reservoir environments and compared with outflow control devices (OCDs) and open hole completions. Due to the uncertainty of heterogeneous reservoirs and the potential for dynamic changes of injection properties, the simulation study showed that with a lower pressure drop compared to OCDs, the fluid front can be managed more efficiently to achieve the desired sweep and maximised ultimate recovery.
The first autonomous injection valve that restricts water into dilated/propagated fractures is developed. This device removes most of the deficiencies of OCDs and eliminates the requirements of running PLT and the prescribed well interventions e.g. closing/opening of sliding sleeves. Instead, it provides operators with a tool that enables the optimised completion to deliver optimum water injection techniques autonomously.
Conventional strategy for developing of giant oil reservoirs with a gas cap involves an optimal production from the oil column before the gas cap is blown down. This paper investigates technical aspects of co-development strategies where demand for the gas may entail earlier exploitation of the gas cap along with the existing oil column development.
Co-development of giant reservoirs with condensate-rich gas cap are particularly challenging due to the presence of significant condensate volumes. The basic strategy of the co-development plan involves producing from a gas cap first under full gas recycling so as to accelerate condensate recovery. This is followed by sales gas production by means of partial gas recycling in conjunction with water injection at gas-oil contact for pressure maintenance purposes. The injection of water at gas-oil contact is intended to provide a water barrier or fence that separates and / or minimize gas cap expansion toward oil. The degree at which sales gas is produced is under pressure maintenance scheme is thus linked to the level of the partial gas recycling and the efficiency of the barrier or fence water injection.
To explore the feasibility of this process, reservoir simulations of mechanistic models were first used to study the reservoir physics of water injection at gas-oil contact for the purpose creating water barrier and /or fence. This was followed by implementation of the co-development scheme using sector models that represent two giant carbonate gas cap reservoirs. The feasibility and merits of the co-development strategy were measured by performance metrics that include condensate recovery, sales gas production, minimum oil loss and fluid migration at gas-oil contact and overall water demand.
The results show that partial recycling along with barrier water injection may provide a mechanism for concurrent gas cap and oil column exploitation. A key factor that underlies the success of the co-development plan is the ability of the water injection at gas-oil contact to recover potential pressure drop in time as gas recycling ratio is reduced by forming effective barrier. This, in turn depends mainly on the reservoir geology and water injection volume and scheme. Moreover, reservoir characteristics that are favorable to the process are lower formation dip angle, smaller surface area at fluid contact and good injectivity of the reservoir rock.
For waterflood management and production optimization purposes, producers and injectors are often grouped into pattern elements based purely on the wells' location. This grouping is often done manually and can be time consuming. Also, for irregular patterns is it not always obvious which wells can be grouped together. The paper presents an algorithm that formalizes the grouping and automatically identifies pattern elements.
The presented algorithm focuses on identification of pattern elements that contain one producer and several neighboring injectors. First, using the wells' coordinates as input data, Voronoi polygons are constructed. Based on the well types (producer or injector) and common edges of Voronoi polygons producer-injector pairs are identified. Pattern elements are constructed by splitting Voronoi polygons of injectors and adding their parts to Voronoi polygons of producers from correspondent wells pairs. In the resulting pattern elements injectors are located in one of the vertices while producers lie inside the element.
The presented algorithm was tested on synthetic examples and proved to identify pattern elements for both regular (e.g. line drive, 5-spot, etc.) and irregular waterflood patterns. Therefore, it is suitable for automated analysis of waterflood patterns in cases where data or time constraints do not allow to implement streamline analysis or other sophisticated techniques. Calculation of voidage replacement for each identified pattern element allows to reveal areas of over-injection as well as areas lacking pressure support, and accordingly adjust rate targets for each injector in order to achieve and maintain a balanced waterflood. Automated identification of waterflood pattern elements helps to timely adjust water injection when new producers come on stream or existing wells shut-in.
The proposed method provides a fast and pragmatic approach of identifying and updating patterns without performing dynamic simulation. Formalized steps of the presented algorithm allow automated identification of waterflood pattern elements. In addition to manual labor savings, it avoids subjectivity and ambiguity that can arise in case of irregular patterns.
Water Injection is part of secondary recovery mechanism which aims to increase oil recovery by increasing or maintaining the reservoir pressure and provide additional pressure support. Most of the time water injection is controlled under matrix injection below the fracture pressure in order to avoid the creation of fractures and risk of bypass oil. However, there are two different mechanisms of fracture creation in water injection: poroelastic fracturing and thermoelastic fracturing. First one will activate above fracture point, while the second one creates below the original fracture point and most of the time missed in reservoir field development Normally fractures can be categorized in 3 groups: - Fractures induced due to increase of injection pressure above pore pressure.
The use of Recovery-factor (RF) versus Pore Volumes Injected (PVI) plot to assess historical and ongoing water flooding strategy and its conformance is a common practice. However, this technique is rarely utilized to guide the future water flooding plan that are often assessed by dynamic modelling. The objective of this paper is to demonstrate an extended application of classical conformance plot not only for the typical use of historical and on-going water flooding performance evaluation but also as a tool to guide the future water flooding strategy.
A collaborative effort between different reservoir management team members were required to obtain the input parameters. This new workflow starts by applying the classic conformance plot technique on prediction scenario of production and injection data from numerical model. In this study, the water flooding conformance plot at layer level is presented. The plot was complemented by the theoretical recovery factor as reference of an ideal water flooding scenario. Subsequently, various injection prediction scenarios from dynamic model were added to the conformance plot template for detailed evaluation. The assessment includes evaluation of water injection rate, timing of water flooding development strategy application, location of injectors and various sensitivity analysis on the injection rates.
Some distinct shapes of conformance plots were recognized during the study. Views and opinion are gathered based on this study to identify the new use of conformance plot as a tool to assess the efficiency of different water flooding strategies. The lesson learnt from this study and the identified conformance plot shape can be beneficial to guide the direction of water injection plan to improve the overall field development plan.
In recent years, low salinity flooding has attracted significant attention as a new method for improving/enhancing oil recovery for both sandstone and carbonate reservoirs. Extensive laboratory experiments investigating the effect of low salinity injection are available in the literature, which show a wide range of responses in the extra oil recovery, ranging from 0 to more than 20%. In this paper, we report experimental programs performed using cores and fluids from several reservoirs in Abu Dhabi with the objective of quantifying low salinity effect in both secondary and tertiary modes and to establish a procedure to screen reservoirs for their suitability for low salinity waterflooding.
To quantify the low salinity effect, multi-rate unsteady state flooding experiments have been performed in both secondary and tertiary mode using reservoir fluids and core material at reservoir conditions of 120 C and 4000 psi. All core floods were performed using 30 cm long and 2 inch diameter core samples. In addition, fluid-fluid interaction experiments were performed using fluids from more than 20 carbonate reservoirs in Abu Dhabi. The fluid-fluid experiments were performed to measure the water in oil micro-dispersion formed upon contacting crude oil with both formation water and low salinity water in order to screen ADNOC's oil reservoirs for suitability for low salinity waterflooding.
The fluid-fluid interaction experiments showed that a number of crude oil samples from carbonate reservoirs in Abu Dhabi were able to create micro-dispersion upon contact with low salinity water. These crude oils are called positive crudes in this paper. On the other hand, several crude oil samples did not show micro-dispersion upon contact with the same low salinity water, hence they are referred to as negative crude oils. Two positive crude oils and two negative crude oils have been used in the flooding experiments. The main conclusions of the study are: 1- The flooding experiments using positive crude oil samples have led to extra oil recovery upon injecting low salinity water, while the negative crude oil resulted in either no or little extra recovery, 2- The data base developed in this study is used for screening ADNOC's oil reservoirs for low salinity waterflooding based on fluid-fluid interaction and shows a significant potential of this promising EOR technology for carbonate reservoirs, and 3- The flooding experiments show up to 6.5% extra recovery in tertiary mode and up to 12.5% extra recovery in secondary mode.
The study presented in this paper demonstrates that the use of fluid-fluid interaction experiments and measuring the creation of micro-dispersion upon contacting crude oil with low salinity is a robust screening method for low salinity water flooding. Moreover, this screening method can lead to significant saving in both time and cost of running low salinity flooding experiments.
Bernardes de Almeida, Sarah (University of Campinas) | Pereira, André (University of Campinas) | Ruidiaz, Eddy (University of Campinas) | Winter, Alessandra (University of Campinas) | Vidal Vargas, Janeth (University of Campinas) | Koroishi, Erika (University of Campinas) | Vidal Trevisan, Osvair (University of Campinas) | Valladares de Almeida, Rafael (Repsol Sinopec Brasil)
The aim of this work is the experimental study of a fractured carbonate rock model for oil recovery evaluation. For this, a new experimental routine regarding petrophysical characterization was developed and validated. The evaluation of oil recovery was performed by mass balance. Also, the heterogeneity of the fractured rock model and the distribution of the saturations was calculated by X-ray computed tomography.
An induced fractured was created adding a longitudinal spacer (
The developed methodology allowed the construction of a porous media with an induced fracture representative from a naturally fractured reservoir. The rock sample was cut lengthwise with a metal saw. A POM spacer was used to represent the fracture, and glass beads filled the fracture in order to give a representative porosity to the fractured rock model. The petrophysical properties of the matrix and the fracture were obtained during each step of the fractured rock model construction. The matrices porosities obtained were 8% and 14%, and the permeabilities 68 mD and 40 mD, respective to each semicylinder of the plug. The fracture porosity and permeability obtained were 1.6% and 146 Darcy, respectively. For the entire fractured rock model, the porosity was 12.5% and the permeability 5 Darcy. The approach to mimic a drainage method reached an initial water saturation of 57%. The recovery factor obtained by the seawater injection at a 0.1 cm3/min flow rate was 30%. An increase of 3% was obtained when the flow was decreased to 0.05 cm3/min. The CT scan measurement yields additional information such heterogeneity of the model through the porosity profile in the fracture, matrix, and the entire fractured rock model.
This work presents an innovative methodology to mimic a natural fractured reservoir model which provided a full routine for petrophysical properties evaluation of a physical model. Besides, computed tomography (CT) scans validated porosity values. Thus, a better understanding of the effects of the flow rate in oil recovery on fractured carbonates rocks and the potential of the model developed for this type of studies could be verified.
SmartWater flooding through the injection of optimized chemistry water has lately become an attractive proposition for enhanced oil recovery in carbonate reservoirs. The wettability alteration towards water-wet conditions caused by favorable surface charge alteration is identified as the main mechanism responsible for oil recovery.
In this experimental investigation, the impact of SmartWater/surfactant synergy on wettability alteration was thoroughly studied by measuring zeta-potentials at calcite/brine and crude oil/brine interfaces using electrophoresis technique. Different types of surfactants are considered including: anionic, amphoteric and non-ionic. Four different water recipes representing SmartWater (10-times reduced salinity) were chosen at a fixed lower salinity as well as the high salinity water (HSW).
The results showed that both anionic surfactants increased the magnitude of the negative zeta-potentials at the interfaces by almost same order of magnitude. The negative zeta-potentials of calcite and crude oil were increased the most with anionic surfactants in NaCl brine. SmartWater showed relatively higher negative zeta-potentials for calcite when compared to Na2SO4 brine and HSW in the presence of anionic surfactant. These results indicate that both NaCl brine and SmartWater can synergistically combine with anionic surfactants for effective wettability alteration in carbonates. Amphoteric surfactant showed a negligible impact on electrical double layer (EDL) expansion and consequently the wettability alteration. The nonionic surfactant induced electrostatic repulsion forces at both calcite/brine and crude oil/brine interfaces in high salinity seawater and as a result it can be considered as the best chemical formulation to reduce interfacial tension and cause wettability alteration in conventional chemical flooding processes. The negligible impact of adding surfactant chemicals on the measured di-electric constant of different brines confirmed the robustness of zeta-potential values reported in this study.
This work for the first time evaluated the synergistic effects of different brines including the SmartWater with surfactant chemicals by measuring zeta-potentials at calcite/brine and oil/brine interfaces. The optimally suited water recipes were identified to synergistically combine with these chemicals to enhance wettability alteration in carbonates. The new knowledge gained from this electro-kientic study will provide practical guidance on how to design efficient chemical flooding processes for enhanced oil recovery in carbonate reservoirs.
Generating in-situ foam is regarded as one of the most promising techniques to overcome gas mobility issues and improve sweep efficiency in both miscible and immiscible gas injection enhanced oil recovery (EOR) processes. Gravity override, viscous fingering and channeling through permeable zones are the major limiting factors that can impair the efficiency of gas floods, mainly due to low density and viscosity of the gas relative to reservoir fluids. Generating strong and stable foam while injecting gas is one way to achieve in-depth conformance improvement in the reservoir.
In this study, a tailored water chemistry (formulated low salinity water) has been evaluated in comparison to using typical high salinity injection water (i.e. seawater) and deionized water in surfactant solutions to determine its overall effect on the produced foam. Using bulk foam tests, foam rheology apparatus and microfluidics device, the foam stabilization factors were analyzed and quantified by measuring the foam-life over time of different surfactants in varying salinity water solutions. In addition, the foam rheological properties were measured under high pressure. The microfluidics device was also used to examine the generated foam strength in porous media.
The results from laboratory experiments clearly demonstrated that the use of tailored water chemistry can improve the stability of produced foam when compared to both high salinity water and deionized water. Low salinity tailored water chemistry solutions resulted in a longer lasting foam, by almost 1.8-3.0 times depending on the surfactant type. The foam rheology results showed that the produced foams with the tailored low salinity water are of higher apparent viscosity when compared to those obtained with deionized water. Both longer foam-life and higher apparent viscosity are indicative of better, stronger and more stable foam. The higher resistance to gas flow was observed in porous media with foams generated using the low salinity tailored water chemistry solutions when compared to those foams obtained with deionized water and high salinity water.
This experimental study, for the first time, demonstrated substantial improvements in the foam stability by using a tailored water chemistry aqueous solution. Such huge foam stabilization improvements obtained with tailored water chemistry has the promising potential to increase the apparent viscosity of injected gas and subsequently more effectively mitigate gas mobility issues encountered in EOR applications.