Fields in the Upper Assam-Arakan Basin have been studied intensely to find prospective sweet spots, perforation intervals for new wells, and potential workover candidates. These forecasts, guided only by dynamic-numerical-model results, have had mixed results when implemented in the field. In this paper, an integrated work flow is proposed for brownfields where oil production is driven mainly by water injection. Produced-water salinity plays a key role, acting as a natural tracer and, thus, helping avoid additional costs for new data acquisition. Is Industry Ready for Brownfields’ Prime Time?
Junwen, Wu (Sinopec Research Institute of Petroleum Exploration and Development) | Wenfeng, Jia (Sinopec Research Institute of Petroleum Engineering) | Rusheng, Zhang (Sinopec Research Institute of Petroleum Exploration and Development) | Xueqi, Cen (Sinopec Research Institute of Petroleum Exploration and Development) | Haibo, Wang (Sinopec Research Institute of Petroleum Exploration and Development) | Jun, Niu (Sinopec Research Institute of Petroleum Exploration and Development)
The high efficient foam unloading agent was developed to solve the problem of unloading of liquid loading gas well with high gas temperature, salinity and high concentration of H2S gas and gas condensate. The Gemini anionic surfactant with special comb structure was synthesized as foaming agent molecule, the modified nanoparticles with certain size and degree of hydrophobicity was adopted as solid foam stabilizer, and the fluorocarbon surfactant was designed and synthesised as gas condensate resistance components. The indoor experiment results show that the foam unloading agent showed good foaming and foam stabilizing ability when the temperature is as high as 150°C, salinity is up to 250000 ppm and H2S concentration up to 2000 ppm. Besides, the foam unloading agent present good liquid carrying ability when the volume fraction of gas condensate is as high as 50%. The field test of this foam unloading agent in Longfengshan north 201-XY well shows that, the average gas production increased from 7256 m3/day to 11329 m3/day, increased by 56%, the average differential pressure between tubing and casing dropped from 2.66 MPa to 2.38 MPa, fell by 10.5%, both liquid yield and gas production are obvious, which prove that the foam unloading agent can meet the demand of drainage gas recovery for high content gas condensate gas field.
Magzymov, Daulet (John and Willie Leone Family Department of Energy and Mineral Engineering and The EMS Energy Institute, The Pennsylvania State University) | Purswani, Prakash (John and Willie Leone Family Department of Energy and Mineral Engineering and The EMS Energy Institute, The Pennsylvania State University) | Karpyn, Zuleima T. (John and Willie Leone Family Department of Energy and Mineral Engineering and The EMS Energy Institute, The Pennsylvania State University) | Johns, Russell T. (John and Willie Leone Family Department of Energy and Mineral Engineering and The EMS Energy Institute, The Pennsylvania State University)
The objective of this paper is to model low-salinity waterflooding by honoring physico-chemical complexity, namely, the effects of reaction kinetics and dispersion. Recent literature provides evidence for the potential of low-salinity water injection to improve oil recovery through wettability alteration through a complex network of reactions. However, there is lack of consensus with respect to the exact chemical species that are responsible for the alteration process. Therefore, in this study, we develop a a simplified binary multiphase reactive transport model that honors the general surface reaction for wettability alteration, but at the same time includes effects of reaction kinetics and dispersion in the governing equations.
We lump the reactants, such as sodium, calcium, and petroleum acids, into two characteristic components based on their contribution to oil or water wetness. The wettability alteration process is modelled as a competition between these primary characteristic components to occupy the rock surface as described by reaction kinetics.
The simulation results show a significant impact of reaction kinetics on the rate of wettability alteration compared to assuming instantaneous equilibrium. In the limiting case of a very slow reaction rate (Da ~ 0), low-salinity injection does not alter the wettability. Particularly, no effect on ultimate oil recovery is observed, regardless of the injected salinity level. For the case of an instantaneous reaction the ultimate oil recovery is sensitive to the injected fluid salinity. Moreover, during fast reactions (Da ~ 10-4), the wettability alteration front moves slower than the injected fluid front caused by excess salt in the solution that desorbs from the rock surface. The delay in wettability alteration is crucial to consider for an appropriate slug size design of low-salinity injection. Lastly, we observe that dispersion does not affect the ultimate oil recovery during wettability alteration as compared to reaction kinetics.
Zhong, Xun (Department of Petroleum Engineering, University of North Dakota) | Pu, Hui (Department of Petroleum Engineering, University of North Dakota) | Zhou, Yanxia (Department of Chemistry, University of North Dakota) | Zhao, Julia Xiaojun (College of Petroleum Engineering, Northeast Petroleum University)
Surfactant EOR received attraction due to its extreme capability to increase displacement efficiency by altering the wettability, lowering the oil/water interfacial tension and ultimately mobilizing the residual oil. However, surfactant systems are widely acknowledged to have large adsorption on rock/clay/sediment solid surfaces, which may result in concentration loss, thus impair the effectiveness of the chemical solution and turn the process into an economically unfeasible case. Surfactant adsorption can be affected by the adsorbents, surfactant structure, experimental temperature and some other factors. Also, the driving force for adsorption varies with different surfactants types. Generally speaking, electrostatic interaction is more prominent for those anionic surfactants, while hydrophobic interaction is more common for nonionic type.
In this paper, the static adsorption behaviors of two surfactants (A1 and N1) on Bakken minerals and Berea sandstone in high salinity and high temperature Bakken conditions (salinity≈290,000 mg/L, temperature=80~105 °C) were studied using spectrometric iodine method, where 0.1 mM I2-0.2 mM KI solution was used as a color developing agent. The primary stability indicated that both surfactants have high compatibility with the Bakken formation brine at high temperature, and their critical micelle concentrations showed a small decrease in the presence of high saline brine. Bakken mineral is relatively complicate, which is composed of quartz, dolomite, calcite and clay, while Berea sandstone contains over 75 wt% quartz. Herein, the effects of surfactant concentration, surfactant type, temperature, adsorbents and salinity on adsorption density were covered, and the impacts of surfactant concentration and adsorbents were found to be more significant. Due to the higher specific surface area and high clay content of Bakken minerals, both anionic surfactant blend A1 and nonionic surfactant blend N1 have pretty high adsorption on Bakken minerals, and the specific adsorption densities of 1000 mg/L surfactant solution were calculated to be 1.74 mg/m2 and 1.69 mg/m2, respectively. Meanwhile, the results also indicated that though the applied surfactant concentration is relatively low, the concentration loss due to adsorption should never be overlooked. Future study on how to effectively reduce the adsorption of surfactant especially in those clay-rich formations is of great significance.
Fluid-rock interactions can modify certain reservoir properties, notably porosity, permeability, wettability, and capillary pressure, and they may significantly influence fluid transport, well injectivity, and oil recovery. The profound influence of low-salinity-brine flooding is primarily based on wettability alteration, while that of CO2 flooding is based on oil swelling, viscosity reduction, and interfacial tension reduction. Low saline brine, when combined with CO2, leads to higher CO2 solubility and diffusion, and increased brine acidity. The low-salinity-brine-CO2 injection further contributes to the synergy of mechanisms underlying the two processes to improve oil recovery.
A reactive transport model, which uses surface complexation reactions (SCR) to describe the equilibrium between the rock surface sites and ion species in the brine solution coupled with transport equation, was developed to predict a set of low-salinity-brine-CO2 flooding experiments conducted on carbonate rocks. While conducting batch simulations of the model, it was shown that the thermodynamic parameters reported in the literature for SCRs in a rock–brine system are not suited to natural carbonate rocks. The same thermodynamic parameters could not fit the model to experimental zeta potential data with pulverized and intact carbonate cores at varying potential determining ion concentrations. The model was further utilized to predict the effluent compositions of potential determining ions in single-phase flooding experiments on natural carbonate cores. The failure of thermodynamic parameters in the prediction of reactive transport single-phase experiments, implies that zeta potential is not enough to optimize such parameters for the reactive transport model.
The reactive–transport model parameters were fitted to the single-phase experiments and a temperature-dependent relationship was generated for the thermodynamic parameters. Then, the optimized model was used in investigating the equilibrium between rock, oil and brine in a set of low-salinity-brine-CO2 flooding experiment. The model showed an incremental recovery of 28% over the formation water flooding, similar to the reported recovery from the experiment. The simulation results show that the incremental recovery can be associated with increased CO2 solubility leading to the formation of
Improving sweep efficiency from heterogenous reservoirs necessitates the injection of gel treatment and/or polymer solution to lower the degree of heterogeneity and to lower the mobility ratio, respectively. In this study, three gel systems were compared with partially hydrolyzed polyacrylamide (HPAM) solution. The purpose of this study was to show the ability of the viscoelastic properties of the HPAM to enhance the sweep efficiency compared to the selected gel systems. The model was one quarter of five- spot pattern with one injector and one producer. The injection rate was 525 bbl/day. The selected simulator to run the scenarios was UTGEL, while the selected gel systems were colloidal dispersion gel (CDG), polymer/chromium chloride gel, and polymer/chromium malonate gel. Two polymer concentrations (0.1 and 0.15 wt. %) were used and three salinities were considered (5000, 10,000, and 20,000 mg/l).
This study showed interesting results regarding the ability of the viscoelastic properties of the HPAM polymer solution to yield recovery factors close or similar to those recovery factors obtained from the selected polymer gel systems. The results also revealed that lowering the salinity of post-treatment water could boost the performance of the polymer solution and make the polymer flooding more effective than gel systems. The results also showed that regardless the duration of injecting the polymer gel system, the HPAM polymer solution still yielded promising results, particularly if low-salinity water was implemented after the treatment.
Cosolvents are commonly injected along with surfactants for successful enhanced oil recovery as they help control aqueous stability, salinity gradient, and microemulsion phase viscosity. Therefore, modeling capability for numerical simulation of cosolvent injection is essential in helping design optimal surfactant floods. Also, the numerical implementation in the simulator should be fully implicit, fully coupled, and highly-scalable to enable full-field models and the higher resolutions often required by chemical flood simulations.
We propose a novel numerical approach to model cosolvents in a fully implicit, fully coupled, parallel, four-phase surfactant flood simulator using the three-level (phase/pseudocomponent/pure component) framework. Three pseudoalcohol components are introduced to the framework for efficient modeling of surfactant phase behavior with alcohols that are partitioned to pseudooil, pseudowater, and pseudosurfactant, respectively. They consist of pure alcohol components which are partitioned to the same pseudocomponent and are distributed to phases as required by the phase behavior equations. New nonlinear solution variables of concentrations are proposed to model transport of pure alcohols, their partitioning into pseudcomponents, and distribution of the pseudoalcohols to phases, along with corresponding equations. The physical properties critical for surfactant flood simulation such as interfacial tension, phase relative permeability, viscosity, and mass density are extended to consider the effect of alcohols.
It is shown that the new numerical approach significantly simplifies implementation of the cosolvent simulation functionality. This is because time consuming and error prone conversion between variables and derivatives, and local iterative solve for the concentrations, are not needed. This simplification enables us to significantly reduce implementation efforts, even within the fully implicit, fully coupled framework. The implementation is validated with various test cases against a widely referenced chemical flood simulator. A large-scale surfactant/polymer flood case with cosolvent injection is successfully simulated with all the important physical processes modeled, with the simulator exhibiting good performance.
Large field scale, four-phase chemical flood simulations with surfactant phase behavior with cosolvents are now practically achievable with the novel numerical approach using the three-level framework without compromising comprehensive physics.
We suggest two new thermodynamic models for the adsorption of ions to the brine/carbonate and brine/crude oil interface. We calibrate the model parameters to the ionic adsorption and zeta potential data. We then investigate the effect of the rock and oil surface charges on the dissolution, wettability alteration, and mechanical properties of the carbonates in the context of modified-salinity water flooding in the North Sea chalk reservoirs.
We modify a charge-distribution multi-site complexation (CD-MUSIC) model and optimize its parameters by fitting the model to a large data set of calcite surface zeta potential in presence of different brine compositions. We also modify and optimize a diffuse layer model for the oil/brine interface. We then use the optimized surface complexation models with a finite-volume solver to model the two phase reactive transport of oil and brine in a chalk reservoir, including the impact of dissolution, polar-group adsorption, and compaction on the relative permeability of chalk to water and oil. We compare the simulation results with the published experimental data.
Al Kalbani, M. M. (Heriot-Watt University) | Jordan, M. M. (Nalco Champion) | Mackay, E. J. (Heriot-Watt University) | Sorbie, K. S. (Heriot-Watt University) | Nghiem, L. (Computer Modelling Group Ltd.)
Barium Sulphate (BaSO4) scale is a serious problem that is encountered during oilfield production and has been studied mainly for fields undergoing water flooding. Chemical Enhanced Oil Recovery (cEOR) processes involve interactions between the injected brine and the formation brine, rock and oil. Very little work has appeared in the literature on how cEOR processes can influence the severity of the mineral scaling problem that occurs in the field and how this can be managed. This study investigates barium and sulphate co-production behaviour, the deposition of BaSO4 in the formation and in the producer wellbore, and its inhibition during polymer (P), surfactant (S) and surfactant-polymer (SP) flooding cEOR processes.
Reservoir simulation has been used in this study, employing homogenous and heterogeneous 2D areal and vertical models. Data from the literature are used to define the parameters controlling the physical and chemical functionality of surfactant and polymer (e.g. oil-water interfacial tension, IFT, polymer viscosity and surfactant and polymer adsorption). Assessment is made of the minimum inhibitor concentration (MIC) required to control scale that is predicted to occur due to changes in brine composition induced by the water and chemical flooding processes. The expected retention and release of a phosphonate scale inhibitor during squeeze treatments in the production wells is modelled.
The high viscosity and more stable polymer slug reduces the mixing between the injected and the formation brines, reducing BaSO4 scale precipitation in the formation and delaying the potential scale risk in the producer wellbore compared to normal water flooding. Polymer adsorption causes retardation of the polymer front compared to the sulphate front, accelerating the scale risk in the wellbore. Polymer with low salinity make-up brine and low sulphate concentration not only improves polymer viscosity and enhances recovery, it also delays and reduces the scale risk in the formation and the producer. During surfactant flooding, from an oil recovery perspective, the optimal phase type and salinity can be any of the three microemulsion phase types, depending on the system multiphase parameters. However, the scaling risk can be different to that in the water flooding case, depending on the IFT, ME phase type, the injected salinity and sulphate concentration. In SP flooding, low salinity make-up brine is preferred to enhance oil recovery, and it also delays and reduces scale risk. The impact of the changing brine composition due to ion reactions affected the required MIC values over time. The impact of the MIC and salinity changes on inhibitor retention and release then influences the treatment volumes required to control scale over field life.
The study shows that barium and sulphate co-production and the evolving scale risk depend on the mobility ratio (which is determined by the injected brine and oil viscosities), on the oil-water IFT and on the level of chemical adsorption. The severity of the scale risk is also impacted by the flood techniques utilised, with the extent of reservoir reactions have an effect on the MIC required to control scale and the squeeze treatment volumes required to maintain production after breakthrough.
Ma, Yingxian (Southwest Petroleum University) | Ma, Leyao (Southwest Petroleum University) | Guo, Jianchun (Southwest Petroleum University) | Lai, Jie (Southwest Petroleum University) | Zhou, Han (Downhole Service Company, CNPC Chuanqing Drilling Engineering Company Limited) | Li, Jia (Downhole Service Company, CNPC Chuanqing Drilling Engineering Company Limited)
We prepared physically linked allyl alcohol polymer/polyacrylamide double network hydrogels via onepot strategy. These double network supermolecular fracturing fluids were found to have a better viscosity at high temperature compared to the conventional polyacrylamide systems. After testing with a rheometer, the fluid viscosity could stay 320 mPa s at 150 C under 170/s shear rate. With NMR and FT-IR results' help, we determined that abundant polar groups of chains were still free, which could complex ions to keep, even enhance the chain stability. Thus, these double network systems showed excellent salt resistance with the non-covalent interactions and physical entanglements, and the viscosity of the allyl alcohol polymer/ polyacrylamide system did not drop but increase. The viscosity in high salinity could increase nearly 40 % compared with the initial situation. Overall, the novel fracturing fluid system could maintain a high viscosity and better rheological properties under high salinity and showed excellent high-temperature stability, to make up the lack of fracturing fluid at this stage. It is expected to potential fluid issues caused by low water quality and harsh downhole temperatures were resolved or mitigated.