bluuebunny/crossref_metadata_2025 huggingface dataset:
Mobility Changes Evaluation of a Polymer Solution at Reservoir Conditions, Polymer Flood Pilot Test Performed in an Extra Heavy Oil Reservoir. Orinoco Oil Belt, Venezuela
Authors: Ramirez Andres , Quevedo Luis , Vasquez Edgar , Ulacio Ivon , Rojas Gonzalo
Published: August 2020

The objective of the study was to estimate which was the effective mobility of a polymer solution injected in an extra heavy oil reservoir, also try to stablish if there was a reduction on effective permeability as injection progressed, and finally estimate the mobility ratio between the reservoir fluid and the injected fluid.

Laboratory analyses were used to evaluate the behavior at surface conditions of the polymer solution before injection, and also the quality of the polymer solution prior injection. Tests were performed to estimate the effect of water reservoir salinity over the polymer solution viscosity, and the effect of Iron and Oxygen ion content present in the solvent used for preparation. After project start up, five fall off tests (pressure transient tests) at different stages of the injection process were performed in order to evaluate the mobility evolution over an extended period of time. The tests were executed every three months after the beginning of the injection of the polymer solution. Other diagnostics techniques were also studied, in order to gain insight of what other variables could affect the injection process, among them: Hall plot diagnostics, and fiber optic data.

The evolution mobility of the polymer solution at reservoir conditions was determined, and as injection progressed, the solution mobility decreased over time for the same concentration, according to results obtained from interpretation of well tests analysis, the mobility decreased from 342 mD/cP to 145 mD/cP. Given that the mobility of the oil was very low (between 0,8 mD/cP and 1 mD/cP), the mobility ratio evolution over time showed that a reduction in polymer effective permeability occurred as injection progressed, favoring the flooding process, also depending of the effective permeability, the mobility compared to water, was almost seven times lower. Laboratory analyses showed and important dependency between shear rate and polymer viscosity in the case of polymer solution prior injection, and also a possible risk of solution viscosity reduction due the high salinity of the reservoir water.

The injection data, fall off analysis, and Hall plot analysis, combined with the results of the laboratory analyses are of great importance for the topic of enhanced oil recovery process in the case of extra heavy oil reservoirs. The results obtained show also that it is necessary to evaluate the actual performance, besides of the core test and simulation results. Finally the knowledge accomplished in this work was used to obtain important information necessary to asset feasibility, in the case of a larger scale implementation of the process.
Fundamental Investigation of Auto-Emulsification of Water in Crude Oil: An Interfacial Phenomenon and its Pertinence for Low Salinity EOR
Authors: Jennifer Duboué , Maurice Bourrel , Théo Dusautoir , Enric Santanach Carreras , Alexandra Klimenko , Nicolas Agenet , Nicolas Passade-Boupat , François Lequeux
Published: August 2020

The phenomenon of auto-emulsification occurring when crude oil is gently contacted with water was investigated using various techniques. This spontaneous emulsification which creates a micro-droplet layer at the oil/brine interface is believed to be linked to the improved oil recovery during low salinity Enhanced Oil Recovery (EOR). Crude oils and a model system (asphaltenes solubilized in toluene) have been studied. Observations were facilitated when using the model system, this allowed to have a better insight into the underlying mechanism of micro-droplet formation. It was established that the water micro-droplets appear in the oil phase due to an osmotic phenomenon: molecular water diffuses from the bulk water which provokes the water micro-droplets swelling. The kinetics of the micro-droplet formation is directly linked to the brine salinity in contact with the crude oil: salt addition slows down the emulsification process. This was further confirmed by the evaluation of the water chemical activity in the oil phase from calorimetry measurements.

Micromodel experiments showed a higher oil recovery when water micro-droplets are present in the system, irrespective of the initial wettability imposed to the micromodel material. Dilatational rheology measurement did not show significant visco-elasticity arising from the water micro-droplet presence; hence, the visco-elasticity difference cannot completely explain the higher recovery. Manipulation of crude oil droplet during dilatational rheology experiments highlighted the impact of micro-droplets on the shape of the macroscopic oil droplet. The nucleation of micro-droplets at oil/brine or solid/oil interface suggests an explanation for the EOR effect. We have observed that micro-droplets organize at the oil/water interface, while others nucleate at the oil/solid interface or sediment on the solid surface. The interaction of asphaltenes with water molecules dissolved in the oil phase may promote wettability alteration. The micro-droplet formation indicates the magnitude of this interaction for a given asphaltenes/brine system.
Field Trial for Wettability Alteration Using Surfactants: Formulation Development In Laboratory to the Implementation and Production Monitoring in an Offshore Reservoir
Authors: Rohilla Neeraj , Katiyar Amit , Rozowski Pete M. , Gentilucci Adrianno , Patil Pramod D. , Pal Mayur , Saxena Prabhat
Published: August 2020

Wettability Alteration (WA) as an Enhanced Oil Recovery (EOR) technique is screened for an oil wet carbonate offshore reservoir in this study. Surfactants can be used to change the rock wettability from oil-wet to water-wet conditions and can lead to unlocking significant incremental oil from oil-wet tight pores. A thorough lab program was designed to develop a wettability altering surfactant formulation and was validated with corefloods and spontaneous imbibition tests at reservoir conditions. Surfactant injection trials at smaller scale were conducted first which were successful. Currently, an ongoing long term surfactant injection pilot is operating to evaluate incremental oil gains.

An optimal surfactant formulation is developed on the basis of favorable phase behavior at reservoir conditions, the ability to alter wettability to a more water-wet state and cause minimal chemical losses on reservoir minerals in the form of adsorption. Surfactant formulations designed in this work are unique and provide high temperature stability (above 70 °C and in some cases up to 120 °C) and high salinity tolerance (> 12 % TDS and up to 22% TDS in some low temperature cases).

The field implementation was done in a systemetic step wise manner to mitigate the risk in implementing such a technology field wide. The first step was to de-risk the long term injection and see if there is any injectivity impairment due to surfactant injection. The current injection trial showed improvement in injectivity that is indicative of changes in wettability. More importantly, there has been no evidence of any injectivity impairment, which paves the way for long term surfactant injection in the field.
Production Optimization of the CO2 Huff-N-Puff Process in an Unconventional Reservoir Using a Machine Learning Based Proxy
Authors: Almasov Azad , Onur Mustafa , Reynolds Albert C.
Published: August 2020

The main objective of this work is to investigate efficient estimation of the optimal design variables that maximize net present value (NPV) for the life-cycle production optimization during a single-well CO2 huff-n-puff (HnP) process in unconventional oil reservoirs. During optimization, the NPV is calculated by a machine learning (ML) proxy model trained to accurately approximate the NPV that would be calculated from a reservoir simulator run. The ML proxy model can be obtained with either least-squares support vector regression (LS-SVR) or Gaussian process regression (GPR). Given forward simulation results with a commercial compositional simulator that simulates miscible CO2 HnP process in a simple hydraulically fractured unconventional reservoir model with a set of design variables, a proxy is built based on the ML method chosen. Then, the optimal design variables are found by maximizing the NPV based on using the proxy as a forward model to calculate NPV in an iterative optimization and training process. The sequential quadratic programming (SQP) method is used to optimize design variables. Design variables considered in this process are CO2 injection rate, production BHP, duration of injection time period, and duration of production time period for each cycle. We apply proxy-based optimization methods to and compare their performance on several synthetic single-well hydraulically fractured horizontal well models based on Bakken oil-shale fluid composition. Our results show that the LS-SVR and GPR based proxy models prove to be accurate and useful in approximating NPV in optimization of the CO2 HnP process. The results also indicate that both the GPR and LS-SVR methods exhibit very similar convergence rates and require similar computational time for optimization. Both ML based methods prove to be quite efficient in production optimization, saving significant computational times (at least 5 times more efficient) than using a stochastic gradient computed from a high fidelity compositional simulator directly in a gradient ascent algorithm. The novelty in this work is the use of optimization techniques to find optimum design variables, and to apply optimization process fast and efficient for the complex CO2 HnP EOR process which requires compositional flow simulation in hydraulically fractured unconventional oil reservoirs.
Economic Assessment of Strategies for CO2-EOR and Storage in Brownfield Residual Oil Zones: A Case Study from the Seminole San Andres Unit
Authors: Ren Bo , Duncan Ian , Male Frank , Baqués Vinyet , Lake Larry
Published: August 2020

Brownfield residual oil zones (ROZ) may benefit from specific strategies to maximize production. We evaluated several strategies for producing from the Seminole ROZ. This ROZ lies below the main pay zone (MPZ) of the field. Such brownfield ROZs occur in the Permian Basin and elsewhere, formed by the action of regional aquifers over geologic time. CO2 can be injected into these zones to enhance oil recovery and carbon storage. Since brownfield ROZs are hydraulically connected to the MPZs, development sequences and schemes should influence oil production, CO2 storage, and net present value (NPV).

We conducted economic assessments of various CO2 injection/production schemes in the Seminole stacked ROZ-MPZ reservoir based on flow simulations. First, we constructed a high-resolution geocellular model from a seismic survey, wireline logs and core data. To calibrate the geological model and constrain the interface between the ROZ and the MPZ, we performed a comprehensive production-pressure history matching of primary depletion and secondary waterflooding. After this, we conducted flow simulations of water alternating gas (WAG) injection into the reservoir while considering several injection/productions schemes (e.g., switching injection from the MPZ to the ROZ, commingled production). For each scheme, various WAG ratios (i.e., reservoir volume ratio between injected water and CO2) were tested to find the maximum oil production and maximum CO2 storage. We assessed the economic results for each WAG ratio case on NPV.

The results from simulating various injection/production schemes showed that simultaneous CO2 injection into the MPZ and ROZ favors oil production. If instead, CO2 is injected into the MPZ and ROZ, then into the ROZ alone, this leads to increased CO2 storage. Storage performance is influenced by the interplay between the crossflow from the MPZ to ROZ and WAG ratios. As the WAG ratio increases, the amount of CO2 stored decreases more for commingled injection cases than for separated ROZ injection cases. Also, the WAG ratio leading to maximum oil production does not necessarily yield the largest NPV, because of the complicated interactions among CO2 consumption, reservoir heterogeneity, and oil recovery.

Brownfield ROZs are common below San Andres reservoirs in the Permian Basin, and they can be exploited to increase oilfields’ NPV and carbon storage potential. Our case study on the Seminole MPZ-ROZ is an analog for other similar reservoirs. We demonstrate that development sequences and WAG ratios influence the performance of CO2 EOR and storage. Thus, this work provides valuable insights into the further optimization of brownfield ROZ development and helps operators to plan flexible storage goals for stacked ROZ-MPZ reservoirs.
QEMSCAN Assisted Interpretation of Imbibition Capillary Pressure for Multi-Porosity Carbonate Rocks
Authors: Alramadhan Aymen , Cinar Yildiray
Published: August 2020

This paper demonstrates the effect of pore systems and mineralogy on imbibition capillary pressure (Pci) of carbonate rocks. A systematic workflow is developed and followed to ensure the data quality of Pci, minimize uncertainty in deriving the Pci from centrifuge tests, and analyze the data together with pore-size distribution from mercury injection capillary pressure (MICP) and mineralogy from Quantitative Evaluation of Minerals by Scanning Electron Microscopy (QEMSCAN). The workflow starts with assessing the centrifuge production data for gravity-capillary equilibrium at each speed. Then the quality-checked data is used to produce six different Pci curves using the analytical and numerical models. The analytical and numerical solutions assess the variability in solutions for various rock types, and ultimately, lead to the selection of the most-representative Pci curve. Finally, the representative Pci curves of varying rock types are analyzed together with the MICP and QEMSCAN data to examine the change in Pci curves as a result of changes in the number and character of pore systems, dominant pore throat radii, and mineralogy.

Findings from this study present insights into the impact of mineralogy and pore systems on the behavior of the Pci curves. From the mineralogy perspective, the presence of dolomite, microporous calcite, or rutile and anatase (TiO2) within the rock composition has a strong influence on the Pci behavior of carbonate rock. The data reveals that the contrast between the micropore and macropore systems of bi-modal carbonates has the strongest influence on Pci. We find that Pci can be clustered based on mineral content for bi-modal carbonate rocks and the degree of communication between micropore and macropore systems. The novel approach presented in this study links the MICP and QEMSCAN data to the imbibition process making the way toward a better dynamic rock typing.
Polymer Flooding - Towards a Better Control of Polymer Mechanical Degradation at the Near Wellbore
Authors: Garrepally Sandeep , Jouenne Stephane , Leuqeux Franpois , D. Olmsted Peter
Published: August 2020

Polymer flooding with visco-elastic polymers is an EOR technique improving both macro and microscopic recovery of oil. Its efficiency can be greatly limited by mechanical and chemical degradation of polymers. When injected in the reservoir, the early few centimeters travelled through the rock are crucial for determining the degradation undergone (degradation being defined as the irreversible loss of viscosity). Our aim is is to establish predictive laws for the degradation of polymer solutions flowing through porous media and for the associated flow thickening which can mobility reduction curves of polymer solutions injected or re-injected through sintered ceramic cores of length varying between 1 and 8 mm, we develop a model for predicting mobility reduction and degradation at any length of porous medium, any flux. The model is built by considering that a single injection at flux J on a core having a length NL0 is equivalent to N successive injections at flux J on a piece of the core of length L0. In linear fow, it is found that degradation increases sharply for the first few millimeters and then tends toward a quasi steady state value after a critical length Lc which decreases for increasing fluxes. This model is then transposed to radial flow. Similarly, there exists a critical distance Dc at which degradation reaches a steady state value. Dc is an increasing function of the injection well radius Rw and tends towards Lc at high Rw since radial flow becomes nearly linear.

Results obtained with the model are then discussed for predicting precisely on which distance degradation will be experienced and for determining if degradation experiments performed in linear flow in the lab are representative of radial flow around a real polymer injector. This study is a first in injecting polymer solutions through cores as short as 1 mm and in predicting mobility reduction and degradation in both linear and radial flow profiles.
A Nanoparticle Assisted CO2 Huff-N-Puff Field Test in the Eagle Ford Shale
Authors: Zheng Shuang , Sharma Mukul , Watts Robin , Ahmad Yusra
Published: August 2020

The primary objective of this work was to investigate the results and the possible mechanisms of oil recovery in a huff-n-puff style improved oil recovery (IOR) field pilot using nanoparticle assisted CO2 injection. A secondary objective was to study the sensitivity of the process to injection volume of nanoparticles and gas, the type of injected gas, soaking period, and the timing of IOR to maximize net present value. An Eagle Ford shale well was produced for 526 days before 167-barrels of nanoparticle treatment and 160-tons of CO2 were injected in 11 cycles into the well, shut-in for 5 days and then put back on production. A simulation study was conducted using a fully coupled geomechanical compositional fracturing and reservoir simulator using data from the pilot well. The primary production was history matched for the fractured horizontal well and the huff-n-puff process with nanoparticle and CO2 injection was simulated followed by a shut-in period. The simulated production after shut-in and the incremental oil recovery was compared with field measured data. The pilot test results clearly show that there is a significant oil rate increase after the nanoparticle and CO2 are injected. Lab results show that nanoparticles can lower the interfacial tension between the water and oil and alter the rock wettability to a preferential water-wet state, which is beneficial for oil production. The simulation studies show that CO2 injection alone results in smaller improved oil recovery and predicts a smaller oil recovery than in the field. This suggests that both the nanoparticles and gas play an important role in increasing the relative permeability to oil and improving oil recovery. Results from the sensitivity study show that larger injection volumes of nanoparticles and gas result in higher oil recovery. Among different injection gases simulated, in this oily window of the Eagle Ford shale, ethane gives the highest oil recovery followed by CO2, methane, and nitrogen. A longer soaking period after the injection also helps to increase oil recovery. It is also shown that it may be better to perform IOR at an earlier stage of primary production to maximize the cumulative oil recovery. Our field and simulation results provide operators with significant new insights into the design of an IOR process that uses nanoparticles with CO2 injection. The integration of field pilot test data with realistic compositional geomechanical reservoir simulation for the first time provides a quantitative estimate of the improvement in oil recovery and insights into the possible mechanisms of oil recovery.
Catalytic Impact of Clays During In-Situ Combustion
Authors: Pope Connor , Ismail Norasyikin Bte , Hascakir Berna
Published: August 2020

Clays are known to act as a catalyst during the in-situ combustion (ISC) process. This work investigates the role of clay in reaction kinetics of a bitumen sample.

Several Thermogravimetric Analysis/Differential Scanning Calorimetry (TGA/DSC) experiments were conducted on a Canadian bitumen and its saturates, aromatics, resins, and asphaltenes (SARA) fractions in the presence and absence of a clay (kaolinite and illite) mixture. The role of each fraction in ISC reactions was investigated at low temperature oxidation (LTO) and high temperature oxidation (HTO) regions by calculating the total activation energy and the heat of combustion. The activation energy calculations were based on the Arrhenius approximation and the heat of reaction was estimated by a simple integration of the DSC curve below the standard zero heat generation line.

Accordingly, we have observed that saturates act like ignitors and their ignition characteristics are enhanced in the presence of clay. Bitumen oxidation in LTO region requires more heat for asphaltenes only in the absence of clay. In the presence of clays, bitumen oxidation in LTO region requires more heat for the mutual interaction of resins with asphaltenes. The required heat for the bitumen oxidation and combustion in HTO region is reduced due to contribution of mainly saturates fraction in the presence of clays. The generated heat (heat of combustion) is increased both in LTO and HTO regions for clay presence case. This is mainly due to the mutual interaction of aromatics fraction with resins fraction in LTO region and the mutual interaction of aromatics fraction with saturates fraction in HTO region. It has also been found that bitumen sample contains emulsified water, which reduces the combustion process performance.
Research and Application of Horizontal Well Infill SAGD Development Technology for Super Heavy Oil Reservoirs
Authors: Tao Liang , Li Geng , Li Lingduo , Shan Jiangtao
Published: August 2020

In order to find effective replacement technology for ultra-heavy oil reservoirs at the late stage of horizontal well cyclic steam injection, pilot test on infill steam-assisted gravity drainage (SAGD) development has been carried out in Xinjiang Oilfield, China. In this study, a fine reservoir geological model was built by combining numerical reservoir simulation with the pilot test to analyze the development mechanism of infill SAGD, and optimize the location of the infill SAGD well group, the infill timing, and the timing of horizontal well turning into production well, as well as the operational parameters of the infill SAGD during start-up phase and production phase. Also, the adjustment techniques at each stage have been worked out. The research results show that the reasonable development technical parameters of the infill SAGD are: the SAGD steam injection well is 5m above the original horizontal well, and the infilling time is after 7 to 8 cycles of steam injection of the original horizontal well; after infilling, the original horizontal well is converted into production well after 2 cycles of steam injection; the bottom hole dryness of steam is greater than 85%, and the production/injection ratio is 1.22 and 1.23. The new technology is expected to increase the ultimate recovery factor by 30%-35%, and will have great reference significance for the development of similar super heavy oil reservoirs.
Impact of Well Shut-in After Hydraulic-Fracture Treatments on Productivity and Recovery in Shale Oil Reservoirs
Authors: Eltahan Esmail , Bordeaux Rego Fabio , Yu Wei , Sepehrnoori Kamy
Published: August 2020

Water invasion, associated with hydraulic fracturing, often causes hydrocarbon-mobility hindrance, known as water blocking. The effect on productivity is largely dependent on saturation profiles inside fractures and formation matrix. Enhancement to hydrocarbon recovery has been reported in some field cases after shutting in wells for long time periods. Here we conduct numerical-simulation studies to investigate the effect of well shut-in on initial productivity and long-term recovery.

We replicate post-fracturing conditions with an extensive fracture network that intermeshes with formation matrix. The models are designed using either logarithmically spaced, locally refined grid or embedded discrete fracture model (EDFM). Starting with varying initial fluid distributions, we compare productivity and recovery of two cases: one that does not start production until after 32 days of shut-in, and another that starts immediately without soaking. For the initial conditions that favor shut-in, we carry out case studies in attempt to find the ideal shut-in conditions for maximum recovery improvement.

Results confirm improvement in early productivity after shut-in for all the considered initial fluid-distribution cases. The majority of cases exhibit net gain in total oil recovery. We report improvement in recovery of as much as 5%, owing to spontaneous imbibition. Imbibition of the injected water into formation matrix causes fluid redistribution and favored mobility for the non-wetting phase, and hence enhanced hydrocarbon productivity. The simulations take into account spontaneous imbibition and gravity segregation, but do not consider geo-mechanical forces, water adsorption or chemical reactions. When capillary forces are neglected, well productivity and recovery decrease, even when the well is not shut in. Such observations underline imbibition counter-current flow as an important production mechanism that should not be neglected in shale-oil-reservoir simulations.
Gas EOR Processes in Tight Unconventionals
Authors: Mydland Stian , Yusra Ilina , Whitson Curtis Hays , Dahouk Mohamad Majzoub , Carlsen Mathias Lia
Published: August 2020

The purpose of this paper is to (1) describe the mechanisms of gas-based enhanced oil recovery (EOR) in tight unconventionals, and (2) emphasize the need for single-porosity model tuning of the dual-porosity model when it is used to model EOR for unconventionals on well or field scale. We study two different gas-based EOR methods that inject and produce cyclically through the same well: The Huff-n-Puff (HnP) method, and a method we will refer to as the Fracture-to-Fracture (F2F) in which every other hydraulic fracture is used for injection and production in each cycle. We show that the recovery mechanisms and EOR target volume for HnP and F2F are fundamentally different.

We argue that the target volume for HnP is a rubblized ("shattered") rock volume adjacent to the hydraulic fracture. To accurately predict the performance of this rubblized region, we use a compositional reservoir simulator that includes molecular diffusion to model the EOR performance of rubble-rock pieces of varying size.

Gridding of numerical models is given considerable attention for both HnP and F2F to show its importance when modeling miscible EOR processes. Coarse gridding may result in significant numerical dispersion, which can falsely yield artificially optimistic recoveries for the HnP process.

Results from this paper show that the primary recovery mechanism for HnP stems from a target EOR volume represented by a rubblized rock volume. The size of the rubble, and in particular its minimum dimension, will control the amount of gas that enters, mixes, and recovers oil from the rubble pore space through a process of Darcy flow, molecular diffusion, and phase behavior that involves swelling, vaporization, and first-contact miscibility conditions. The F2F method is not particularly affected by the rubblized region, but instead targets recovery from the entire rock volume between hydraulic fractures; this EOR process is akin to a conventional miscible-displacement mechanism with a much larger EOR target than HnP.

The F2F method is presented in this paper as an alternative to the HnP method to show that HnP is not necessarily the best or the only EOR strategy in tight unconventionals. The EOR target volume for F2F is potentially much larger than for HnP, as everything between the fractures may be swept with a piston-like efficiency. However, the response time (i.e. the time before uplift in production is observed) can be much longer for F2F than HnP, depending mainly on the fracture spacing and matrix permeability.
Comparison of Surfactant-Polymer and Polymer Flooding in a High Temperature Sandstone Reservoir
Authors: Masduki Agus , Syafwan Muhammad , Nursyahid Bambang , Armpriester Andrew , Dean Robert , Dwarakanath Varadarajan , Malik Taimur , Meaux Dwight , Slaughter Will , Thach Sophany
Published: August 2020

Results from two field trials designated as Minas Surfactant Field Trial 2 (SFT2) and Polymer Field Trial (PFT) are presented. Quantitative tracer interpretations were used to estimate sweep and displacement efficiency and confirm the performance of both SFT2 and PFT. The pilot patterns in both SFT2 and PFT consisted of a central producer surrounded by six chemical injectors and further confined by six hydraulic control wells that injected water alone. In order to make quantitative comparisons, both the surfactant-polymer and polymer pilots were run at the same mobility ratios to understand if incremental recovery was a function of improved volumetric sweep or increased displacement sweep efficiency. The results of the two pilots show that at the same well spacing and mobility ratio, incremental sweep is very similar and significantly higher than pre-chemical waterfloods. An important finding of the tracer tests is that water injectors should not be used to confine chemical injectors as the water tends to bypass the higher viscosity polymer chase and potentially disrupts the oil-bank. The results from the pilots indicate that for a mature, waterflooded reservoir, surfactant-polymer flooding was preferable as it lowered the final remaining oil saturation and increased oil recovery. Polymer flooding mainly accelerated oil recovery by recovering additional oil from unswept zones and had minimal impact in a mature reservoir. Interwell tracer technology combined with moment analyses were used to make quantitative comparisons of both processes and allowed for several technical insights. This is the first time in literature that a quantitative comparison of surfactant-polymer flooding and polymer flooding alone has been presented.
Analyzing the Dynamics of Mineral Dissolution During Acid Fracturing by Pore–Scale Modeling of Acid–Rock Interaction
Authors: You Jiahui , Lee Kyung Jae
Published: August 2020

Hydrochloric acid is commonly used in acid fracturing. Given that the interaction between acid and rock affects multiphase flow behaviors, it’s important to thoroughly understand the relevant phenomena. Darcy–Brinkman–Stokes (DBS) method is most effective to describe the matrix–fracture system among the proposed models. The objective of this study is to analyze the impact of acid–rock interaction on multiphase flow behavior, by developing a pore–scale numerical model applying DBS method. The new pore–scale model is developed based on OpenFOAM, which is an open source platform for the prototyping of diverse flow mechanisms. The developed simulation model describes the fully–coupled mass balance equation and the chemical reaction of carbonate acidization in an advection–diffusion regime. Volume of Fluid (VOF) method is employed to track liquid and gas phase interface on fixed Eulerian grids. Here, penalization method is applied to describe the wettability condition on immersed boundaries. To compute the numerical solutions of discretized equations, finite volume method is applied, where the equations of saturation, concentration, and diffusion are solved successively, and momentum equation is solved by using Pressure–Implicit with Splitting of Operators (PISO) method, respectively. The simulation results computed by this numerical model have been validated by experimental results. Different injection velocities and the second Damkohler numbers have been simulated to investigate their effects on the evolving porosity and rock surface area. The newly developed pore–scale model in this research provides the fundamental knowledge of physical–and–chemical phenomena of acid–rock interaction and their impact on acid transport. The modelling results describing mineral aci dization will help us to implement an effective fracturing project while reducing environment impacts.
Instow a Full Field, Multi-Patterned Alkaline-Surfactant-Polymer Flood – Analyses and Comparison of Phases 1 and 2
Authors: Pitts Malcolm J. , Dean Elio , Wyatt Kon , Skeans Elii , Deo Dalbir , Galipeault Angela , Mohagen Dallas , Humphry Colby
Published: August 2020

An Alkaline-Surfactant-Polymer (ASP) project in the Instow field, Upper Shaunavon formation in Saskatchewan Canada was planned in three phases. The first two multi -well pattern phases are nearing completion. Beginning in 2007, an ASP solution was injected into Phase 1. Phase 1 polymer drive injection began in 2011 after injection of 35% pore volume (PV) ASP solution. Coincident with the polymer drive injection into Phase 1, Phase 2 ASP solution injection began. Phase 2 polymer drive began in 2016 after injection of 47% PV ASP solution. Polymer drive continues in both phases with Phase 1 and Phase 2 injected volume being 55% PV and 35% PV, respectively. Phase 1 and Phase 2 oil cut response to ASP injection showed an increase of approximately four times from 3.5% to 12 to 16% and an increase in oil rate from approximately 3,200 m3/m (20,000 bbl/m) to 8,300 m3/m (52,000 bbl/m) in Phase 1 and from 2,200 m3/m (14,000 bbl/m) to 7,800 m3/m (49,000 bbl/m) in Phase 2. Phase 1 pattern analysis indicates the pore volumes of ASP solution injected varied from 13% to 54% PV of ASP with oil recovery percentage increasing with increasing injected volume. Oil recoveries in the different patterns ranged from 3% OOIP up to 21% OOIP with lower oil recoveries correlating with lower volume of ASP injected. The response from some of the patterns correlates with coreflood results. Wells in common to the two phases show increase oil cut and oil rate responses to chemical injection from both Phases 1 and 2. Oil recovery as of August 2019 is 60% OOIP for Phase 1 and 57% OOIP for Phase 2. Phase 1 economic analysis indicated chemical and operation cost would be approximately C$26/bbl resulting in the decision to move forward with Phase 2.
Experimental Investigation of the Effect of Polymer Viscoelasticity on Residual Saturation of Low Viscosity Oils
Authors: Jin Julia , Qi Pengpeng , Mohanty Kishore , Balhoff Matthew
Published: August 2020

We performed coreflood experiments to determine the effect of polymer viscoelasticity on the residual saturation of low viscosity oils by varying the rock type, wettability, polymer rheology, and flow conditions. Several authors have shown that polymers, if viscoelastic, can recover a significant amount of capillary-trapped oil, beyond inelastic floods, in water-wet sandstones. We demonstrate that the polymer viscoelastic effect works for several different rock types, both water-wet and oil-wet media, and with low viscosity oils which broadens the applicability found in previous works. In polymer field studies, the rheology can be tailored to maximize the effect based on our findings.

Eleven corefloods were performed in Bentheimer, Boise, and Berea cores. Two of the cores were made oil-wet using dichlorodiphenylsilane (DCDPS) and chlorotrimethylsilane (CTMS). The cores were initially saturated with brine and then displaced by low viscosity (4-10 cp) crude oil until steady state was reached. Brine was then injected to displace the oil until steady state and residual oil saturation was reached. In most experiments, HPAM polymer was then injected at ∼1 ft/day; the polymer rheology was tailored via the salinity, concentration, molecular weight, and degree of hydrolysis. Once steady state was reached, a second polymer solution (with the same viscosity but higher salinity) was injected until a final oil saturation was reached. A reduction in oil saturation was observed in all corefloods in which the polymer was viscoelastic. On average, the oil saturation was reduced by 5.6% in the first polymer flood and 4.0% in the second, high salinity polymer flood. Higher recoveries were found for some experiments in which the first polymer was more elastic (higher dimensionless Deborah number). Final oil saturations as low as 5% were achieved using only polymer (and no surfactant). Results were not dependent on the rock type (e.g. Bentheimer versus Boise) but the effect was more pronounced in water-wet cores than those changed to oil-wet.
A Comparison Simulation Study of GDWS-AGD EOR Process Performance Using CO2/APG Alternatives in South Rumaila Oil Field, Iraq
Authors: Al-Mudhafar Watheq J , Wojtanowicz Andrew K
Published: August 2020

To date, feasibility studies of the Gas and Downhole Water Sink-Assisted Gravity Drainage (GDWS-AGD) process for the South Rumaila oil field have considered using Carbon Dioxide gas injection to enhance oil recovery. As availibility of CO2 is limited and its cost considerable it might be also feasible to use natural gasAssociated Produced Gas (APG), that has been recently tested as an alternative solvent to enhance oil recovery. The paper reports on a simulated comparison of the APG or CO2 application in the South Rumaila oil field. The comparison metrics include field recovery factor, water cut in oil and water producers, Gas Oil Ratio in oil producers, cumulative gas injection, and average saturation.

In the study, the GDWS-AGD process installation comprises 20 vertical APG injection wells completed at the top of the reservoir to build a gas cap in the oil pay zone. In addition, eleven horizontal oil-producing wells are placed at the bottom of the oil pay zone with six horizontal water drainage (sink) wells below the oil-water contact (OWC). The two horizontal leg installation may be made from a vertical well with 7-casing dual-completed (from two kick-off points) in the oil payzone and in the bottom water (below OWC) with two horizontal well legs and the two 2-3/8 inch tubings in each well. In a dual-tubing design of the process the two horizontal well legs produce independently. If only one tubing is used production from the water sink well is hydraulically isolated inside the vertical well by a packer. In either design, the water sink well is operated with a submersible pump.

In this study, the GDWS-AGD process with APG is considered for the upper sandstone member/South Rumaila Oil Field, located in Iraq to improve oil recovery. The Rumaila field has an infinite acting-aquifer with very strong edge water drive. In the GDWS-AGD, the bottom water drainage would not only reduce water cut and water cresting, but would also significantly reduce the reservoir pressure, resulting in improving gas injectivity by significantly reducing the need for high injection pressure and gas solubility will be also reduced in the immiscible mode. Significant improvement with the GDWS-AGD process - oil recovery increased from 76.5% by CO2 to 82.5% by APG and water cut was readily controlled resulting in more rapid reduction with APG (from 95% to less than 5%) than that with CO2 in all horizontal oil producers. The results show that the use of APG alternative to CO2 for the GDWS-AGD process not only improves water-cresting and controls water cut, but also enhances gas injectivity and significantly improves oil recovery.
Characterization of Carboxylate Surfactant Retention in High Temperature, Hard Brine Sandstone Reservoirs
Authors: Pinnawala Gayani , Davidson Andrew , Taylor Isbell , Yang Hyuntae , Slaughter Will , Kim Do Hoon , Malik Taimur , Dwarakanath Varadarajan
Published: August 2020

Large hydrophobe Carboxylate surfactants (MW above 1000) are a relatively new class of surfactants developed for surfactant flooding during chemical enhanced oil recovery (EOR) processes. The presence of carboxylate groups and alkoxylate groups in the molecules provides stability and salinity tolerance at high temperature and in high salinity environments. Many high temperature reservoirs have injection and reservoir brine containing high concentrations of divalent ions making them prime targets for using carboxylate surfactants. Much of the earlier literature showed successful carboxylate applications at high pH during alkali-enhanced flooding, as the high pH stabilizes the carboxylate groups. Such processes are not feasible in the presence of hardness at high temperatures. We present an approach where we use an alkali buffer wherein the pH is adjusted from highly basic to near neutral. Under such conditions we demonstrated low retention and high performance in terms of phase behavior and coreflood oil recovery.
A Simulation Case Study of Gas Injection Pilot in Eagle Ford
Authors: Rogers J. Brandon , Basbug Basar , Firincioglu Tuba , Ozgen Chet
Published: August 2020

This paper focuses on simulation modeling of a gas injection pilot operated in the Eagle Ford Shale play. The main objective of this case study is to understand the flow mechanisms in the reservoir due to hydraulic fracturing of multiple wells and gas injection operations.

A dual porosity numerical reservoir simulation model coupled with geo-mechanics was built to investigate the hydraulic fracturing and flow dynamics of the pilot area using a sophisticated numerical reservoir simulator. The methodology used in this study integrates the hydraulic fracturing process, multi-phase flow and geo-mechanics within the reservoir simulation. In this approach, the change in mean stress for each grid block is implicitly solved together with pressure and the other flow variables using poro-elastic information. Geologic, geo-mechanical and reservoir properties were gathered from the static geo-model. The actual stage-by-stage hydraulic fracture treatment jobs were simulated to investigate the stimulated rock volume (SRV) characteristics of the study wells. The simulation model was calibrated to match the hydraulic fracturing, flow back, depletion and multiple huff and puff cycles. Oil, water and gas production/injection data together with pressure data were matched during calibration. Additional sensitivity runs were performed to examine the potential benefits of gas injection under different operational scenarios.

The results show that the Eagle Ford pilot area is quiet in terms of natural fractures. There is an indication of weak zones that provide preferential connectivity paths for water and gas flow. These weakness points could be related to the lithology or natural fractures. They were defined as easily breakable planar zones in the model. The most important knowledge gained from the calibration of the gas injection period is the establishment of connectivity paths and their poro-elastic behavior during gas injection. The results showed that oil swelling and vaporization of oil into gas are the two mechanisms that impact the huff-n-puff performance. Maintaining most of the injected gas around the huff-n-puff pattern also improves the performance.
Review of Canadian Field Cases of Chemical Floods with Associative Polymer
Authors: Delamaide Eric
Published: August 2020

Polymer flooding is now a well-recognised and mature technology to increase hydrocarbon recovery, used in many parts of the world. Given its success, operators are looking at new opportunities for polymer and are trying to push the technical barriers even further. One of these barriers is high salinity which is detrimental to the economics of polymer floods with standard polymers, and thus requires other solutions.

Associative polymers are polyacrylamide-based polymers well known for their good resistance to high salinity due to their structure and as a result they could be very promising for use in fields with high TDS. However, they have so far seen little use in field applications due to their perceived plugging tendency, high permeability and mobility reduction which make them more adapted to near-wellbore treatment.

Most if not all of the field projects involving associative polymers have taken place in China and in Canada, but little has been published so far. Since public information is available for the Canadian projects, the aim of this paper is to present the field experience of associative polymers in these Canadian projects.

The paper will focus on presenting four field cases, Bodo, Mooney and Suffield (2), all in Western Canada. Bodo is a polymer flood while Mooney and Suffield are both polymer and alkali-surfactant polymer projects. Although public information is not always complete, what is available provides some useful and much needed insight on the performances of associative polymers in the field.

Our analysis of these four field cases suggests that associative polymers can be injected without special difficulty provided they are well chosen, that is they need to be sufficiently associative to outperform HPAM but not too much in order not to plug the reservoir. These results should comfort engineers who have so far been reluctant to use associative polymers due to lack of field experience.

Very few field cases of polymer flood involving associative polymers have been published so far and this paper attempts to shed some light on the performances of associative polymer in some unpublished projects. These positive results may incite engineers working on projects where associative polymers could find a use to consider them.
Polymer Chemical Structure and its Impact on EOR Performance
Authors: Beteta Alan , Nurmi Leena , Rosati Louis , Hanski Sirkku , McIver Katherine , Sorbie Kenneth , Toivonen Susanna
Published: August 2020

Polymer flooding is a mature EOR technology that has seen an increasing interest over the past decade. Co-polymers of Acrylamide (AMD) and Acrylic Acid (AA) have been the most prominent chemicals to be applied, whereas sulfonated polymers containing 2-Acrylamido-tertiary-butyl sulfonic acid (ATBS) have been used for higher temperature and/or salinity conditions. The objective of this study was to generate guidelines to aid in the selection of appropriate polyacrylamide chemistry for each field case. Our main focus was in sandstone fields operating at the upper end of AMD-AA temperature tolerance, where it needs to be decided whether sulfonation is required. The performance of the polymer throughout the whole residence time in the reservoir was considered since the macromolecule can undergo some changes over this period.

Several key properties of nine distinct polymer species were investigated. The polymers consisted of AMD-AA co-polymers, AMD-ATBS co-polymers and AMD-AA-ATBS ter-polymers. The polymers were studied both in their original state as they would be during the injection (initial viscosity, initial adsorption and in-situ rheology) as well as in the state which they are expected to be in after the polymer has aged in the reservoir (i.e. in a different state of hydrolysis and corresponding viscosity retention and adsorption after ageing for various time periods). We note that the combination of viscosity retention and adsorption during the in-situ ageing process has not been typically investigated in previous literature, and this is a key novel feature of this work. Each of the above parameters has an impact on the effectiveness and the economic efficiency of a polymer flooding project. The content of ATBS was limited to 15 mol%. Buff Berea sandstone was applied in the static and dynamic adsorption experiments.

The majority of the work was carried out in seawater at temperature, T = 58°C. Under these conditions AMD-AA samples showed maximum viscosity and lowest adsorption when the content of AA was moderate (20 mol%). When the AMD-AA polymers were aged at elevated temperature, the AA content steadily increased due to hydrolysis reactions. When the AA content was 30 mol% or higher, the viscosity started to decrease, and adsorption started to increase as the polymer was aged further. Thermal stability improved when ATBS was included in the polymer structure. In addition, sulfonated polyacrylamide samples showed increasing initial viscosity yields and decreasing initial adsorption with increasing ATBS content. For most of the samples, the maximum observed apparent in-situ viscosity increased when the bulk viscosity and relaxation time of the sample solution increased.

The information generated in this study can be used to aid in the selection of the most optimal polyacrylamide chemistry for sandstone fields operating with moderate/high salinity brines at the upper end of AMD-AA temperature tolerance.