Khodaparast, Pooya (Department of Energy and Mineral Engineering and EMS Energy Institute, The Pennsylvania State University, University Park) | Johns, Russell T. (Department of Energy and Mineral Engineering and EMS Energy Institute, The Pennsylvania State University, University Park)
Surfactant floods can attain high oil recovery if optimum conditions with ultra-low interfacial tensions (IFT) are achieved in the reservoir. A new equation-of-state (EoS) phase behavior model based on the hydrophilic-lipophilic difference (HLD-NAC) has been shown to fit and predict phase behavior data continuously throughout the Winsor I, II, III, and IV regions. The state-of-the-art for viscosity estimation, however, uses empirical non-predictive models based on fits to salinity scans, even though other parameters change, such as the phase number and compositions. In this paper, we develop the first-of-its-kind microemulsion viscosity model that gives continuous viscosity estimates in composition space. This model is coupled to our existing HLD-NAC phase behavior EoS.
The results show that experimentally measured viscosities in all Winsor regions (two and three-phase) are a function of phase composition, temperature, pressure, salinity, and
Current HLD-NAC theory and most simulators represent multicomponent mixtures with three lumped components, where the excess phases are also assumed pure. This can cause significant errors, and discontinuities in chemical flooding simulation for surfactant mixtures. We coupled the HLD-NAC and pseudo-phase models to develop an EOS for microemulsions where surfactant, polymer, alcohol, alkali and monovalent/divalent ions can partition differently into the excess phases and microemulsion phase as temperature and pressure are changed.
We develop a pseudo-phase model to calculate partitioning of components between lumped components or namely pseudo-phases. The pseudo-phase model is based on a transformed composition space. The partitioning model is based on different mechanisms such as cation exchange like reactions for ions and surfactant hydration properties. Next, the three-pseudo-component HLD-NAC EOS is used to calculate curvature of the interface and microemulsion phase composition based on pseudo-phases. That is, the microemulsion phase consists of a curved ruled surface between water and oil pseudo-phases. Polymer partitioning is updated based on micelle radius. Finally, the phase compositions are converted back from pseudo-phase space to the original composition space.
This model is the first comprehensive and mechanistic flash calculation algorithm based on HLD-NAC and pseudo-phase theory to calculate microemulsion properties for mixtures without the assumption of pure excess phases. This algorithm allows for modeling of the chromatographic separation of surfactant, soap, alcohol, alkali and polymer components in chemical flooding processes. Current microemulsion models usually ignore the differing partitioning of components between excess and microemulsion phases, generating discontinuities that slow computational time and adversely impact accuracy.
Chen, Szu-Ying (University of California at Santa Barbara) | Kaufman, Yair (University of California at Santa Barbara) | Kristiansen, Kai (University of California at Santa Barbara) | Howard, A. Dobbs (University of California at Santa Barbara) | Nicholas, A. Cadirov (University of California at Santa Barbara) | Seo, Dongjin (University of California at Santa Barbara) | Alex, M. Schrader (University of California at Santa Barbara) | Roberto, C. Andresen Eguiluz (University of California at Santa Barbara) | Mohammed, B. Alotaibi (Saudi Aramco) | Subhash, C. Ayirala (Saudi Aramco) | James, R. Boles (UCSB) | Ali, A. Yousef (Saudi Aramco) | Jacob, N. Israelachvili (UCSB)
Waterflooding via injection of chemistry-optimized low-salinity – also, low ionic strength/concentration – waters, such as SmartWater, is becoming increasingly attractive for improved oil recovery, especially in carbonate reservoirs. In this manuscript, we describe the results from a series of experiments and theoretical modeling to determine the mechanisms that govern the
We measured various interrelated crude-oil(
The results presented in this manuscript are of practical significance to provide a better understanding of SmartWater flooding mechanisms in carbonates at multiple length scales, including subnano-, nano-, micro-, and macroscopic scales. The new fundamental understandings presented in this study will also guide the optimization of SmartWater flooding processes in other reservoir systems.
A miscible injectant was used in a single injection well pilot in the Yates field to mobilize remaining oil in the gas cap and accelerate gravity drainage. Nitrogen, CO2 and recycled gas injection, all immiscible with Yates oil due to low original and current reservoir pressure, have been used historically to assist the gas-oil gravity drainage (GOGD) development. The result of immiscible injection has been a lowering of the gas-oil contact, a thinning of the oil column, and leaving a remaining oil saturation in the gas cap of up to 40 percent. A hydrocarbon mixture rich in ethane and propane and miscible with Yates oil was injected in a CO2 injector for six months after which the well was returned to pure CO2 injection.
Data collection during the pilot included repeat saturation logging of a newly drilled observation well, well tests of nearby horizontal producers, frequent gas and oil sampling, and chromatographic analysis. Phase behavior PVT experiments were also conducted which confirmed miscibility of the injectant and improvement over CO2 injection. Numerical simulation of pilot performance was also used as part of the interpretation.
Pilot results to date show a doubling of oil rate at peak over base oil decline, breakthrough in horizontal producers within 3-5 months matching an a priori prediction from numerical simulation, 10 percent reduction in oil saturation in the target interval in the gas cap, and the return of two wells to continuous production after having been shut-in due to high gas-oil ratios. Early interpretation of pilot results showed that most of the incremental oil and back produced enriched hydrocarbons came from one well. During the follow-up CO2 injection phase, one of the horizontal wells completed in the gas cap (unlike other pilot producers), was redrilled deeper into the oil column to improve the pilot areal and vertical sweep.
The pilot design, results, and interpretation will be discussed. Results from the pilot will be used to support evaluation of a field wide development, which could lead to substantial incremental reserves and extension of the field life.
The Niobrara and Codell in the Wattenberg Field of the Denver-Julesburg Basin (DJ Basin)have been in the centerstage of horizontal drilling and multi-stage hydraulic fracturing ever since 2007. Based on the current well completion strategy, oil rates drop to 20 bbl/day/well in five years of primary production. The cumulative primary production in the first five years amounts to 3%. Nonetheless, a substantial amount of producible hydrocarbon still remains. In this paper, we propose a most feasible enhanced oil recovery (EOR) technique for the Niobrara and Codell and other similar unconventional oil reservoirs. Realizing the unavailability of CO2 in the area while having easy access to methane, ethane, propane and butane, we designed an injecting gas consisting of ethane enriched with methane, propane and butane for EOR. A dual-porosity compositional model was constructed using data from seismic, well logs, core analysis, and production performance. After successful history matching, as well as verification with seismic and microseismic interpretations, a producer with five years of production history was converted to an EOR-gas injector in the numerical model. We used the model to determine the optimal injection gas composition for producing the largest amount of oil. We also studied the contribution of molecular diffusion at the fracture-matrix interface for the incremental oil recovery from gas injection. Model results indicate that converting three producers to injector wells, and producing from the remaining eight producers, yielded total oil recovery of 4.68% in fifteen years of production with 13% of which attributed to gas injection EOR.
The objective of this research was to develop a surfactant formulation for EOR in an oil-wet, high-salinity, fractured dolomite reservoir at ~100°C. A key requirement was achievement of interfacial tension (IFT) sufficiently low to spontaneously displace oil from the matrix by buoyancy. The formulation developed to do so was a blend of lauryl betaine and C15-18 internal olefin sulfonate, supplemented by a smaller amount of i-C13 ethoxylated carboxylate, all thermally stable and commercially available surfactants although the carboxylate not in quantities required for largescale EOR processes. Proportions of the three surfactants for injection in hard sea water were selected using equilibrium phase behavior results and estimates of IFT obtained by a novel technique based on the manner in which oil exits a small, vertically-oriented, rectangular oil-wet capillary cell as it is displaced upward in the cell by surfactant solution. The ability to recover oil from an oil-wet dolomite core was confirmed by an Amott imbibition cell experiment in which 50% recovery was observed for a core initially fully saturated with oil. The formulation's ability to generate strong foam in porous media was presented earlier in SPE-181732-MS. Research at Rice for three additional projects having carbonate reservoirs but different crude oils, brines, and temperatures of at least 60°C demonstrated formulation versatility by showing good oil recovery by core floods with modestly adjusted proportions of the same three surfactants (SPE-184569-MS, 2017; SPE-190259-MS 2018, US Patent 9,856,412). In the first two of these cited studies, the foamed formulation was injected to recover crude oils from a novel model fracture-matrix system.
Favorable interactions between injection gas and crude oil are crucial for successful carbon dioxide (CO2) recovery processes. The miscibility behavior and thereby the flooding scheme changes with the pressure applied. Although first contact miscibility (FCM) flooding schemes result in most efficient recovery processes, in many cases multiple contact miscibility (MCM) provides economically viable recovery rates already at lower injection pressure. Thus, the determination of the miscibility pressure is a key step in the lab evaluation for CO2 EOR. Miscibility enhancing additives are able to improve the interactions between CO2 and crude oil leading to reduced miscibility pressure.
This paper illustrates an easily applicable procedure to identify the pressure required for full miscibility. Using a pressure resistant sapphire cell the phase behavior of mixtures of different crude oils and CO2 with and without additives was investigated at common reservoir conditions. The effect of the additives on the physical phase behavior of CO2/crude oil mixtures and the benefit that can be achieved by their application will be discussed.
The miscibility gaps are determined by measuring the phase behavior of CO2/additive/crude oil mixtures as a function of pressure and temperature. The pressure required for full miscibility (physical minimum miscibility pressure (MMPP)), coming along with an FCM scheme, can easily be detected as the pressure above which the miscibility gap closes and a homogeneous mixture is obtained. Another important point, which was determined in this study, was the critical point of the miscibility gap. Its corresponding pressure is the maximum value of the minimum miscibility pressure (MMP) from a thermodynamical viewpoint, above which MCM schemes take place. Hence, knowledge of the critical point of the mixture is an easy to use method to estimate the maximum value of the MMP for a specific reservoir. Adding proper additives to the CO2 improves the miscibility of injection gas and crude oil. By this the miscibility gap shrinks and both the MMP and the MMPP will be reduced significantly compared to the pure CO2/crude oil system.
The method presented is a proper, quick, and low-cost alternative to the time-consuming and expensive slim tube experiments commonly used in the oil industry to measure the MMP. Since at pressures above the MMP an MCM procedure is ensured by physics it is the lowest injection pressure that needs to be applied to ensure miscible CO2 EOR. Reducing the MMP and the MMPP using proper additives can lead to a more economical CO2 flood or can even make reservoirs accessible for this technology, which are naturally not.
Mixing of an asphaltenic oil with light gases (e.g., CO2) and/or depressurizing such a crude oil can lead to phase separation in which a second liquid phase L2 -highly concentrated in asphaltene- is formed. Asphaltene may precipitate or deposit out of the second liquid phase. This causes formation damage, wettability alteration, and recovery reduction. While asphaltene phase behavior have been studied under static conditions (where equilibrium is imposed), the behavior of asphaltene under dynamic flow conditions is relatively unexplored. Here, we investigate the coupling of asphaltene phase behavior and flow in porous media. As such, two asphaltenic crudes are characterized using the PC-SAFT equation-of- state. The fluid models were then used to fit the experimental asphaltene deposition data under static conditions. Subsequently, asphaltene flow and deposition was studied during miscible gas flooding where four phases (water, oil L1, gas, and second liquid L2) are present. Our results show that (i) wettability alteration increases the mixing zone and decreases both the displacement and sweep efficiencies; (ii) asphaltene deposition, hence wettability alteration and formation damage are maximal near the producer.
The recovery factor of Eagle Ford shale is estimated around six percent, which means that considerable amount of oil will be left behind after primary production. A major technique to enhance oil production in Eagle Ford could be gas injection since waterflooding is not plausible. This paper presents a novel inhouse multi-component, multi-phase, dual-porosity numerical model including molecular diffusion. This model evaluates ethane-rich gas EOR schemes to recommend on the injection mechanisms and maximize the production performance in support of field design and applications.
There is a great interest to develop an enhanced oil recovery technique for the unconventional shale reservoirs to increase its oil production beyond the primary production. The model, we present, was developed to address this issue while adhering to the thermodynamic complexities of the confined space, which includes crossing the phase boundaries during phase evolution, the wall effects in efficient and computationally robust procedures. It also determines the effect of molecular diffusion on transport mechanisms. The analysis of production data from Eagle Ford wells is used in conjunction with the simulation results to evaluate the increase in recovery after gas injection.
To model the flow for both primary and enhanced recovery, an appropriate model involving advective flow and molecular diffusion is needed since Darcy flow is by no means the dominant flow mechanism considering the average pore throat size measured in Eagle Ford formation. One major requirement for the process is providing adequate residence time to the injected gas for molecular diffusion to take place across the matrix-fracture interface. The simulation results demonstrate that the ethane-rich produced gas injection as an enhanced oil recovery mechanism will improve the production. In particular, an increase of at eleven percent in cumulative oil production is achieved. Furthermore, we present the usefulness of the formulation in analyzing pressure and rate variation with time as well as forecasting future performance of unconventional reservoirs.
In this paper, we present a new compositional diffusivity model which determines the appropriate injection mechanisms using different gas injection scenarios for the field applications in Eagle Ford. Our method provides a better understanding of the physical phenomena of fluid flow processes in unconventional reservoirs which affect the reservoir performance for both primary and enhanced recovery.
Rodriguez, L. (SNF) | Antignard, S. (SNF) | Giovannetti, B. (SNF) | Dupuis, G. (SNF) | Gaillard, N. (SNF) | Jouenne, S. (Total) | Bourdarot, G. (Total) | Morel, D. (Total) | Zaitoun, A. (Poweltec) | Grassl, B. (Pau University, IPREM)
Most Middle East fieds present harsh reservoir conditions (high temperature, high salinity, low permeability carbonates) for polymers used as EOR mobility control agents. Traditional synthetic polymers such as partially hydrolyzed polyacrylamide (HPAM) are not thermally stable. At temperatures above 60°C, acrylamide moieties hydrolyze to sodium acrylate which ultimately leads to precipitation and total viscosity loss. Thermal stability can be improved by incorporating monomers such as ATBS or NVP.
In a previous paper, we reported the development of terpolymers where incorporation of NVP was shown to provide improved stability up to 120°C. Unfortunately, NVP increases the cost of the polymer and limits its molecular weight. Additionally, NVP also causes drifts in the polymers composition, thereby impairing injectivity in low permeability carbonate rocks. The price of the final product, to achieve a given viscosity, is approximately 3 times higher compared to conventional HPAM polymers and 2 to 2.5 times higher than SPAM polymers (sulfonated polyacrylamide). More recently, we reported the synthesis of NVP-free polymers incorporating different mol precentages of ATBS. The ATBS containing polymers are cheaper than the NVP polymers and enable dosage reductions of up to 50%, to obtain the same viscosity. Additionally, they outperformed the NVP polymers in terms of injectivity and thermal stability, as well as pushed the stability limits from 105-110°C up to 130°C and 140°C in brines withTDS of 230 g/L and 100 g/L respectively.
In this study, we present new data for viscosity and thermal stability of NVP-free polymers optimized in terms of process and molecular weight. In particular, the thermal stability study was completed with NMR spectroscopy and Size Exclusion Chromatography (SEC) analysis to obtain information on the evolution of the chemistry and the molecular weight distribution of the polymers during long-term aging. NMR and SEC analysis reveal that the reduction of the viscosity during aging is due to an evolution of the polymer chemistry (conversion of acrylamide and ATBS units in acrylates) as well as chain scission. The incorporation of ATBS, into the polymer backbone, appears to slow down hydrolysis and limits the viscosity loss. There was no modification of the chemistry observed for the polymer having the highest level of ATBS and any viscosity loss observed is directly related to a decrease in molecular weight.
The optimization of the NVP-free polymers redues the dosage by one third, making them very attractive from an economic standpoint. Both NMR and SEC techniques, have been shown to be efficient tools to understand the mechanism involved in viscosity changes for polymer solutions during long-term thermal aging.