bluuebunny/crossref_metadata_2025 huggingface dataset:
Fracture-Fluid Chemistry Optimization to Improve Hydrocarbon Recovery for Shale and Tight Assets
Authors: Pinnawala Gayani W. , Tang Guo-qing , Salman Mohamad , Nizamidin Nabi , Wu Stanley , Malik Taimur , Inouye Art , Dwarakanath Varadarajan
Published: April 2024

The active development of unconventional shale and tight reservoirs worldwide has helped unlock vast quantities of hydrocarbons in recent years. Hydraulic fracturing operations in horizontal wells is the most common method applied to unconventional reservoirs to unlock hydrocarbon resources by undergoing multiple fracturing stages. A common mixture of friction reducer, scale inhibitor, and other situational additives along with a carrier fluid, (brackish or recycled produced water) make up the completion or frac fluid. Often, the frac fluid is a colloidal suspension, as noted by the larger particle size distribution within the fluid. When exposed to reservoir conditions (elevated temperature, high formation brine salinity, high divalent ion concentration), frac fluids can destabilize due to the presence of polyacrylamide acting as a flocculant. Such behavior causes phase-separation and precipitation resulting in formation damage. Another scenario is the rapid production rate decline seen in hydraulically fractured horizontal wells. Typically, their production rates rapidly decline until stabilizing at a low terminal rate. Overcoming these trends to improve recovery is a major challenge. Fracture Fluid Chemistry Optimization (FFCO) technology development focuses on increasing recovery by designing and optimizing fracturing fluids for stimulation of shale formations. This stimulation fluid maintains clean fractures and penetrates deeper into the fracture network, mobilizing more hydrocarbons by altering rock wettability and lowering interfacial tension (IFT). The surfactants also alter the relative permeability to a more favorable state in the propped fractures. This work describes a workflow to optimize treatment fluids for injection into shale and tight rock reservoirs. The workflow incorporates rock and fluid property measurements and compatibility assessments between rock, reservoir fluids and frac fluids at the laboratory scale.
A Comprehensive Approach to Modelling Air Injection Based Enhanced Oil Recovery Processes
Authors: Gutiérrez D. , Moore R. G. , Mallory D. G. , Ursenbach M. G. , Mehta S. A. , Bernal A.
Published: April 2024

Modelling of air-injection-based processes for enhanced oil recovery is a challenging task, mostly due to the complexity of the chemical reactions taking place. Also, the applicability of currently available kinetic models is limited to the reservoir systems they were originally developed for. The objective of this study is to derive a general chemical reaction framework that could be used to develop a kinetic model for a variety of crude oils (i.e., light or heavy oils).

The work is based on the modelling of high-pressure ramped temperature oxidation (HPRTO) experiments, and combustion tube (CT) tests, performed on three different oil systems: a volatile oil which is near critical at reservoir conditions (44°API), a low-shrinkage light oil (35°API), and a bitumen sample (10°API). A kinetic model was derived for each of the cases based on the history match of a HPRTO experiment. The resulting model was validated by history matching a CT test for each of the oils. An important feature of all these experiments is that they were performed at representative reservoir pressure conditions.

The modelling approach chosen is an extension of the methodology originally proposed by Belgrave et al. in 1993, which is arguably the most comprehensive kinetic model available in the air injection literature. However, their model was developed from experiments performed on Athabasca bitumen, and it fails to represent the air injection process as it occurs in light oil reservoirs encountered at high pressure. For example, Belgrave's model is based on the deposition and combustion of semi-solid residue commonly known as "coke", which is rarely present during the combustion of light oils at high pressure.

As in Belgrave's model, this study also describes the original oil in terms of maltenes and asphaltenes. The main difference lies on the presence and importance of oxygen-induced cracking reactions, as well as the combustion of a flammable mixture, which takes place in the gas phase. Also, a unique feature of these simulations is that, apart from history matching traditional variables such as thermocouple temperatures, fluid recovery and gas composition, they also capture changes in the physical properties of the produced oil, such as viscosity and density, which enhances the robustness of the approach and represents an important step towards the development of predictive simulation models.

This work is unique as it is the first time a single kinetic modelling approach is capable of modelling the in situ combustion of different oil types, which allows the consolidation of a general theory for air injection processes. Moreover, since the pseudo-components representing the fuel are not present in the original oil, the method is not limited to a fluid characterization in terms of maltenes and asphaltenes, but could potentially be applied along with any type of characterization of the original oil.
Relative Permeability Modeling for CO2 Storage Using Physically Constrained Artificial Neural Networks
Authors: Mukherjee S. , Johns R. T.
Published: April 2024

Injection of CO2 into saline formations is regarded as a promising tool to reduce atmospheric emissions. Although often overlooked, one of the key parameters that governs the flow and transport of the plumes is relative permeability. Relative permeability curves are generally measured sparingly, assumed fixed once measured, and/or altered significantly as a history match parameter to fit injection and production data even though relative permeability has a physical significance and is dynamic within a reservoir.

We use limited field data to develop an artificial neural network (ANN) model to generate contours of relative permeability in saturation-connectivity space and predict relative permeability for both CO2 and brine phases as paths are traversed in that space. Experimental data (only one drainage and imbibition curve) is used to tune the ANN model and determine the contours and hysteresis paths, so that relative permeability and trapped saturations can vary automatically depending on the path taken. The new relative permeability model is based on the idea of state and path functions, so that there is a unique value of relative permeability for a given set of input physical parameters, avoiding relative permeability discontinuities. Further, relative permeability in the ANN model is physically constrained to lie between zero and one at the appropriate limits. We show how to fit experimental data and test the predictive capability of the model on a gas-water relative permeability dataset with multiple hysteresis scans not used in the tuning process.

Results show that the developed model fits the limited data (relative permeability and residual or trapped saturations) better than classical Corey curves and has the significant advantage that it can also predict well other hysteresis curves and residual saturations not used in tuning. To our knowledge, we are the first to show the predictive power of physically constrained ANN with such a limited field dataset. The mean squared error for the predicted relative permeability for the hysteresis scans in the gas-water relative permeability dataset is on the order of 10-5. The approach easily handles any hysteresis path in saturation-connectivity space including current problematic ones where water is completely vaporized by CO2 or when CO2 is completely dissolved in brine. With this approach, relative permeability can vary spatially, continuously, and physically according to dynamic saturation history facilitating a faster and more accurate simulation.
Numerical Modeling Assessment of CO2-EOR and Sequestration Potential in a Light-Oil Carbonate Reservoir
Authors: Al-Ghnemi M. , Ozkan E. , Amini K. , Kazemi H.
Published: April 2024

This numerical study investigates the potential of mutually fulfilling EOR and sequestration objectives of carbon dioxide (CO2) injection into a hypothetical light-oil, carbonate reservoir. Formation and fluid properties were selected considering the ranges published in the literature for light-oil, carbonate reservoirs. The potential sources of CO2 were assumed to be the upstream and downstream activities in the reservoir geographic area, such as atmospheric emissions from refineries and steam boilers operating in nearby fields. Therefore, the example case is intended to explore sequestration and recovery potential of enhanced oil recovery (EOR) by CO2 injection (CO2-EOR) — not in isolation but as part of regular oil-field operations.

The light oil carbonate reservoir meets the EOR screening criteria for miscible CO2 flood. An equation of state was used to characterize the reservoir hydrocarbon system to generate phase envelope and minimum miscibility pressure (MMP) via a ‘mixing cell method’ and benchmarked against published correlations.

Compositional numerical simulations of waterflooding, CO2-flooding, water-alternating-gas with CO2 (WAG-CO2), and methane (CH4) were performed under the assumptions of anticipated reservoir management and operational conditions. The EOR and sequestration potentials of CO2 flooding and WAG-CO2 were quantified by CO2 gross and net utilization ratios (GUR and NUR, respectively) and retention capacity (RC).

Simulation results yielded the highest incremental oil recovery for the WAG-CO2 flooding surpassing that of the continuous CO2 flooding by a factor of 1.75. Typical GURs and NURs for continuous CO2 flooding were 29,000 SCF/STB and 9,600 SCF/STB, respectively. For WAG-CO2, the gross CO2 utilization ratio was 8,300 SCF/STB and the net CO2 utilization ratio was 3,100 SCF/STB, which indicated considerably lower CO2 requirements per barrel of incremental oil than those for the continuous CO2 injection case.

Although the CO2 utilization ratios indicated a higher EOR efficiency of WAG-CO2, the RCs of the two methods were similar: 33% and 36% for the continuous CO2 and WAG-CO2 injection cases, respectively. This amounted to 83% more CO2 being sequestered for the continuous CO2 injection compared to WAG-CO2.

Adding 2,000 ppm H2S impurity and 10 – 20 % CH4 to the injected CO2 mixture caused little effect on the efficiency of CO2-EOR and sequestration. Therefore, recycling produced CO2, contaminated by the reservoir gases, does not impair the EOR and sequestration objectives of CO2 injection into the light-oil, carbonate reservoir considered in this study.

The results of this work corroborate the conflicting effectiveness of continuous-CO2 and WAG-CO2 methods in meeting the EOR and CO2 sequestration objectives. Operational restrictions, such as to accommodate continuous injection of CO2, the WAG-CO2 method requires at least two parallel patterns with alternating CO2 time periods, further exacerbate the optimization considerations.
A CO2-modified Surfactant for Chemical Flooding and Reducing Carbon Emission
Authors: Chen Shaohua , Huang Tianping , Wang Jinxun , AlOtaibi Mohammed B
Published: April 2024

A CO2-modified alkyl polyglycoside (C-APG) surfactant was synthesized from a commercial APG product under mild reaction conditions including a low temperature at 50 °C and a low pressure of 2.5 bar. With this reaction, CO2 was successfully incorporated into APG molecules for efficient reduction of carbon footprint. The performance of applying C-APG as chemical flooding for improved oil production application in carbonate reservoirs with heavy crude oil was investigated and compared with its precursor - APG surfactant. The synthesized C-APG was characterized by FTIR and the physicochemical properties of both APG and C-APG including compatibility, surface tension, interfacial tension (IFT) were evaluated. Both surfactants were compatible with the high-salinity water (HSW) and had a similar critical micelle concentration (CMC). However, C-APG exhibited a much pronounced effect in reducing IFT between oil and water. The IFT of C-APG was 10-fold lower than original APG surfactant, suggesting great potential in chemical flooding for oil displacement. Micromodel test showed that the produced heavy oil by injection of APG or C-APG solution was further enhanced after water flooding. C-APG shows higher effectiveness on oil displacement due to lower IFT and stronger emulsification. Core-flooding oil displacement test indicated that C-APG injection resulted in a lower differential pressure and a higher cumulative oil production comparing APG chemical flooding. The produced fluids from C-APG flooding and extended water flooding exhibited very strong emulsification comparing the fluids produced by APG flooding. The incomplete phase separation resulted in an underestimated oil displacement efficiency by C-APG flooding. This study shows a great potential of C-APG surfactant in terms of CO2 reduction and improving oil production.
Aqueous Nanobubble Dispersion of CO2 for Enhanced Oil Recovery – Coreflooding and Huff-n-Puff Experiments
Authors: Lawal Tesleem , Wang Hao , Mirzaei-Paiaman Abouzar , Okuno Ryosuke
Published: April 2024

This paper presents an experimental study of aqueous nanobubble dispersion of carbon dioxide (CO2-NB) for enhanced oil recovery. CO2-NB was compared with brine and slightly supersaturated carbonated water (eCW) in corefloods with Berea sandstone cores and dead oil at room temperature. CO2-NB was also compared with a mixture of CO2 and brine with no NB in high-pressure high-temperature huff-n-puff experiments with live oil-saturated tight Kentucky sandstone cores using three different fracture-matrix configurations.

Coreflooding results showed that the displacement of oil by CO2-NB yielded a delayed breakthrough, in which the oil recovery factor at breakthrough (RFBT) was 9.1% original-oil-in-place (OOIP) greater than RFBT in the brine case. The displacement of oil by eCW did not show such an increase in RFBT, but showed a long-term gradual increase in oil recovery after the breakthrough. The increased RFBT by CO2-NB can be attributed to the nucleation of a CO2-rich phase near the displacement fronts, where the metastable aqueous phase releases CO2 to the oleic phase while the nanobubbles of CO2 with capillary pressure release CO2 to the surrounding aqueous phase. That is, the partially miscible displacement of dead oil by the in-situ generated CO2-rich phase could have enhanced RFBT by CO2-NB in comparison to the immiscible oil displacement by water in the brine case. Huff-n-puff experimental results showed a systematic increase in oil recovery by using CO2-NB in comparison to CO2-brine (with no NB). In the CO2-NB case, the annular, artificial, and combination fractures had oil recoveries of 34%, 36%, and 39% OOIP, respectively. In the CO2-brine case, they were 245, 22%, and 28% OOIP, respectively.
Chemical Tracer Application to Compare Napthalene Sulfonic Acid and Sodium Fluorobenzoic Acid as Part of Polymer Field Trial Project
Authors: Tumewu Putranda Yeremia , Silalahi Ester Tio Minar E.
Published: April 2024

Tracer testing is the effective method to characterize subsurface, especially to investigate well connectivity or fluid pathways, estimate traveling velocity of injected fluid, assess the breakthrough times of the tracers between injectors and producers, and evaluate swept pore volume and sweep efficiency particularly in Enhanced Oil Recovery (EOR) operation. Fluoro-benzoic acid (FBA) remains the primary and most common liquid phase tracer in oil industry, but recent laboratory and geothermal field test using Naphthalene Sulfonic Acid (NSA) also looks very promising. The NSAs are thermally stable at reservoir conditions, cost about a tenth of the cost of FBAs, and have a much lower detection limit when tested using High Performance Liquid Chromatograph (HPLC). The drawback is that they have not been widely tested in oil reservoir but have proven themselves in the laboratory tests and in geothermal reservoirs.

This paper describes performance test of NSA as chemical tracer in oil reservoir in direct comparison with proven conservative tracer, FBA by pairing an NSA tracer with a proven FBA tracer in the same injector well as part of IOR polymer pilot project. Six different types of NSAs were injected at the six different injection wells. In addition, six different types of FBAs were also injected at the same wells to make comparative data with NSA at producer wells. The tracer test was performed for 170 days with relatively constant injection and producing rate to maintain steady state condition in the reservoir. The injection and production rates were balanced for the test duration. Bottom-hole temperature is about 85°C.
Low-Tension-Gas Flood in a High-Temperature and Heterogeneous Sandstone Reservoir
Authors: AlAbdullah Mohammad B. , Delshad Mojdeh , Niu Fangya , Mohanty Kishore , Sepehrnoori Kamy , Li Jianshen , Zhou Nancy C. , Lu Meng , Miao Jijun
Published: April 2024

This study explores Low-Tension-Gas (LTG) flooding as a hybrid low-tension surfactant and nitrogen gas-enhanced oil recovery method for a high-temperature (90-100°C), heterogeneous (permeability 0.06 µD-1180 mD), sandstone reservoir. We began with history-matching two corefloods, an outcrop, and a reservoir core, employing the in-house UTCHEM simulator. Flow parameters were derived from these core floods, and fluid properties were ascertained from lab experiments. A 0.6-acre pilot-scale model in UTCHEM, based on field data and geostatistics, was used to simulate the LTG process.

The comprehensive field scale sensitivity study indicates an additional oil recovery factor (RF) between 11-18% from LTG injection, influenced primarily by residual oil saturation to waterflood, injection rate, LTG slug size, and surfactant concentration. Gravity segregation between gas and microemulsion phases, affected by reservoir vertical heterogeneity, emerged as a critical factor. A lower kv/kh ratio led to a more stable front with a moderate gas override. An optimal chemical injection design involves 1 wt% surfactant concentration within 1 pore volume of LTG slug. Higher injection rates resulted in increased oil recovery and shorter pilot duration, though constrained by field operational limits. Adjusting foam quality during LTG injection affected gravity segregation, necessitating further lab experiments for correlation with gas mobility reduction. Foam shear thinning could enhance field foam injectivity without significantly impacting cumulative oil recovery. Increasing the injection rate within allowable injection bottomhole pressure is recommended for field implementation to prevent fracture induction. This is the first study that extensively explores the impact of reservoir and design parameters for LTG injection for challenging reservoir conditions.
Streamline-Based Robust Rate Allocation Optimization for Polymer Flooding Considering Geological Uncertainty
Authors: Zhang Ruxin , Datta-Gupta Akhil
Published: April 2024

Optimal injection/production rate allocation is an integral part of effective reservoir management for enhanced oil recovery (EOR). Field-scale rate allocation optimization with hundreds of wells can be time consuming and complicated by the multitude of operational and well related constraints. The common practice is to either do the optimization manually or limit the simulation-based optimization to a single realization which ignores the geological uncertainty and causes suboptimal rate allocation.

This paper proposes a streamline-based robust optimization algorithm that accounts for geologic uncertainty while allocating injection/production rates to maximize sweep efficiency and hydrocarbon recovery. The algorithm follows a sequence of time intervals. For each time interval, the well rates of each realization are tuned iteratively based on well pair rate multiplier that is consolidated for all realizations to account for geological uncertainty. The robust optimization is based on an expected value of the performance index over multiple realizations, and can be tuned to include appropriate risk tolerance. The optimization process continues to the next time interval, until the end of the field life.

Power and utility of the proposed algorithm is applied to a large-scale polymer flooding field case (base model). Multiple geological realizations are generated by grid-connectivity transformation (GCT) based on the base model to account for geological uncertainty. Before optimization, multiple history-matched realizations are selected and divided into training realizations and one blind test realization. The training realizations and base model are used in their entirety to conduct robust optimization, but the base model is chosen to conduct nominal optimization for comparison purposes. The optimal rate schedules from both the robust optimization and the nominal optimization are applied to a blind test realization to examine the impact of geological uncertainty. The optimal rate schedule from the robust optimization consistently outperformed that from the nominal optimization in terms of sweep efficiency, hydrocarbon recovery, and polymer utilization.
Experimental Characterization to Support a FAWAG Project in an Offshore Pre-Salt Field
Authors: Vieira R. A. M. , dos Santos S. S. F. , do Nascimento L. P. T. , de Souza D. M. P. T. , da Silva C. N.
Published: April 2024

This work describes the experimental characterization of foam flow in a Pre-Salt field, carried out to support the implementation of a FAWAG pilot currently under evaluation. Foam performance was quantitatively determined as a function of surfactant concentration, water composition, gas composition, water saturation, oil saturation, and rock permeability. Surfactant adsorption on the rock and its partition in the oil phase was also measured. These results were used to estimate parameters to be entered into foam models available in commercial reservoir simulators. Other fields subject to gas injection for secondary or tertiary recovery purposes, or even CCS/CCUS projects, are potential beneficiaries of this information.
Synergistic Impact of Low Salinity and Surfactant on Wettability Alteration in Carbonates
Authors: Reinoso B. S. , Mohanty K. K. , Panda M.
Published: April 2024

The waterflood recovery is often low in tight carbonate reservoirs, which tend to be heterogeneous and oil-wet/mixed-wet. Wettability alteration is a promising strategy for improving oil recovery in such reservoirs. This study aims to improve oil recovery in such a reservoir in West Texas. The mineralogy is determined by XRD analysis. The zeta potential is measured for the drill cuttings. Contact angles are measured on core trims, and imbibition experiments are conducted to evaluate wettability alteration. The optimum salinity was determined to be produced water diluted 40 times from zeta potential measurements. The synergy between low-salinity water and surfactants yielded more than 40% oil recovery in spontaneous imbibition experiments. The addition of sulfate ions and weak acids improved spontaneous imbibition. The results of core flood tests underscored the efficacy of surfactants in improving oil recovery through wettability alteration after waterflooding. This study highlights the potential of low-salinity and surfactant-assisted flooding to improve oil recovery in limestone reservoirs.
Foam Flood in Yates Reservoir for Improving Oil Recovery
Authors: Panda Manmath , Valdez Raul
Published: April 2024

The Yates reservoir is a major, multibillion-barrel legacy oil reservoir in West Texas discovered in 1926. Oil production mainly comes from the San Andres formation, which is a highly fractured dolomite rock. The fractures in the reservoir provide preferential pathways for fluid flow, leading to early breakthrough of injected fluids and reduced sweep efficiency. As a result, even though a number of secondary and tertiary injection techniques have been implemented over the field's history to improve the sweep, only a third of the Original Oil In-Place (OOIP) has been recovered thus far. The majority of the bypassed oil is believed to be in the matrix.

This paper describes a foam flood that has been implemented at Yates to sweep the bypassed oil in the matrix rock. Foam flooding in the Yates reservoir involves injecting a surfactant, along with the produced gas into the reservoir. The surfactant reduces the surface tension between the gas and liquid phases, creating a stable foam. This foam is then injected into the reservoir to improve oil recovery. In the case of the Yates reservoir, foam flooding can address several challenges specific to fractured carbonate reservoirs. Foam flooding helps mitigate poor sweep efficiency issue by reducing the mobility of the injected gas, forcing it to contact and displace more oil within the matrix.

An extensive laboratory program was implemented to select suitable surfactants that produce stable foam in Yates fluids and rock system. Several corefloods were also conducted at the reservoir conditions to evaluate the benefits of a foam flood at Yates. The core flood results indicate that an incremental oil recovery of 13-16% can be achieved by a foam flood.

A 3D compositional simulation model around the injection pattern YFU 4045 was developed to evaluate the field implementation of the foam flood at Yates. The simulation model used the foam parameters derived from the laboratory experiments. The simulation results indicated that a field pilot can be implemented to achieve improved recovery in pattern YFU 4045.

A continuous foam injection pilot was implemented for a period of six months by simultaneously injecting produced gas and surfactant solution with average concentration of 1200 ppm that resulted in an average foam quality of 50%. Several surveillance techniques were implemented to confirm foam formation, such as, setting a down hole pressure gauge and running injection profiles with and without the foam. A gas tracer was also injected to verify if gas diversion was achieved because of the foam injection.

Analysis of the pattern producer performance shows a significantly higher incremental oil recovery after the foam flood compared to the simulation model. A dimensionless scaling technique was developed using the foam flood pilot results to expand the foam flood to other areas of the field.
Full-Field Polymer Flooding Project – Principles and Challenges at the Kalamkas Oilfield
Authors: Kushekov R. M. , Sagyndikov M. S. , Ispanbetov T. K. , Pourafshary P. , Shyrakbayev D. A.
Published: April 2024

The Kalamkas oilfield is one of the largest brownfields in Kazakhstan and has a 45-year development history. With a 27% recovery factor, it still has the potential to make a valuable contribution to Kazakhstan’s oil production. Polymer flooding (PF) is supposed to be the most effective technique to reveal this potential since the first pilot projects in 80’s conducted. Nowadays, when new explorations are expensive, the application and expansion of such technologies are critical to field development. This article presents the main features of modern polymer flooding implementations. Features such as mobile polymer flooding units and their complex reservoir-oriented injections help to create cost-effective staged full-field planning. Strong selection criteria consisting of basic geological and production characteristics were developed to target the "sweet spots" of the reservoir. An analytical method for oil production forecasting was applied to evaluate the feasibility of each selected area. The consistency and duration of polymer flooding areas were identified based on the forecasting results. Moreover, this pragmatic approach is time-saving and allows fast decision-making compared to simulation studies. 26 new polymer areas involving 80 injection wells (~15% of Kalamkas injectors) and over 600 offset producers were selected for polymer flooding. New areas were ranked in terms of their predicted efficiency and considered to be covered by polymer flooding step-by-step for the next 20 years. With the availability of mobile polymer flooding units, it is possible to switch units from completed areas to new involving areas, significantly improving the project’s cost-effectiveness. Another feature of our case is that polymer flooding areas can be grouped by geographical principles and their technical reasons for using the same type of polymer. Thus, polymer flooding units handle multiple formations located at different depths even with different rock and fluid properties. It is also observed that most PF areas are expected to be economically feasible with up to 70% pore volume injection; this parameter can be increased even further if local polymer price is optimized. In conclusion, the developed full-field polymer flooding project is expected to provide 7.5% incremental oil recovery. The current experience of PF pilot projects and lessons learned provide a strong foundation for future extension strategy. Full-field polymer flooding project at the Kalamkas oilfield is expected to be one of the largest chemical EOR projects in the Commonwealth of Independent States (CIS) despite harsh water conditions (~130 g/l salinity) compared to other projects such as Daqing, Mangala, Marmul, and Pelican Lake.
Pattern Recognition for Wettability Alteration with Surfactants in Carbonate Reservoirs by Using Machine Learning
Authors: Yao Y. , Wei M. , Ali M. , Qiu Y. , Cui Y. , Leng J.
Published: April 2024

Surfactants are widely applied agents to interact with the adsorbates on carbonate rock surface, which could alter wettability from oil-wetness to water-wetness and thus enhance oil recovery. Surfactant huff-puff is often conducted to achieve wettability alteration and has been applied under various conditions. Currently, many investigations have been reported to apply conventional data analysis methods to analyze different sets of surfactant huff-puff projects. Yet the application of machine learning algorithms to reveal the inherent patterns is rarely reported. In this study, we integrate principal component analysis (PCA) with hierarchical clustering algorithm (HCA) to uncover the hidden patterns embedded in global surfactant huff-puff dataset. PCA is effective to transform the original data space to principal components space, where five principal components could represent the information of original nine reservoir and fluid parameters and maintain around 90% of total variance. Based on the transformed data space, HCA is implemented with optimized structure, including Euclidean distance measure, Ward’s linkage method and three clusters. It shows that HCA obtains a normalized mutual information score, V-measure score, and Fowlkes-Mallows index of 0.75, 0.75 and 0.83, which suggests the effectiveness and reliability of the newly proposed PCA/HCA procedure. The PCA/HCA is able to group similar surfactant huff-puff treatments into the same cluster. Three distinct cluster patterns are found in the surfactant huff-puff dataset. The second cluster includes most of the high temperature and high salinity carbonate rocks, while the third cluster includes chalk rocks with fairly low permeability and high porosity. The first cluster contains surfactant treatments conducted with low temperature and low divalent concentrations. Besides, the analog reasoning results show that the PCA/HCA is able to provide valuable experiences for designing surfactant treatments and predicting future performance for new candidate surfactant treatment projects. This procedure could greatly save time and cost.
A Systematic Experimental Study of Low Salinity, Carbonated Water and Low Salinity Carbonated Water EOR Injection Schemes in Carbonate Reservoir Conditions
Authors: Alhashboul A. A. , Farzaneh A. S. , Sohrabi M. S.
Published: April 2024

Smart Water (SW) can be defined as brine that has been chemically adjusted/optimized in terms of salinity and ionic composition or carbonation (CO2 enrichment). The aim is to create a brine with an optimum chemical & ionic composition such that it changes the equilibrium of the oil crude/brine/rock interaction (CBR). Recently, combining more than one EOR method in hybrid mode has gained attention; several SW hybrid modes have been investigated with positive results. The most promising hybrid mode is combining low salinity injection (LSI) with Carbonated Water Injection (CWI). A carbonated Low Salinity Carbonated Water Injection (LSCSWI) study was carried out to both study the effectiveness and explore the prospects of combining carbonated water (phase behaviour), with low salinity (wettability alteration) mechanisms. A series of high-pressure/temperature carbonate reservoir core flood experiments were performed at reservoir conditions (100ºC - 3100 psig), so the incremental oil recovery factor and differential pressure behaviour of Low Salinity (LS), Carbonated Water (CW). LSCW and CO2 EOR injection schemes could be compared.

A near perfect oil recovery often associated with miscible CO2 core flooding experiments was achieved. However, field implementations where gravity override challenges of CO2 injection are faced, do not produce oil recovery %'s near the recovery factors that are achieved in miscible CO2 core flooding experiments. The highest incremental oil recovery % IOIP of the waterflooding based injection modes was achieved by tertiary LSCSW, with a value of 28.49%, followed by CSWI at 23.18%, and finally LSSWI at 5.5%. The magnitude effect of the Dp drop caused by the carbonated water's new gas phase that was produced with the effluent was higher than the wettability alteration increases of Dp that was caused by reducing the salinity of the injected brine. Several observations supported the claim that mechanisms of wettability alteration, associated with LSI and phase behavior change associated with CWI, work simultaneously. The wettability alteration mechanism that was triggered by reducing the salinity of injected brine is much more dependent on the remaining oil saturation, in order for it to have a significant positive influence on oil recovery.

To the author's best knowledge, there has not been a systematic experimental investigation that compared these four EOR recovery methods, by using the same carbonate reservoir core sample, live crude oil sample and injected brines, at the same reservoir conditions.
Core-To-Field Scale Simulations of Low Salinity Polymer (LSP) Flooding in Carbonate Reservoirs Under Harsh Conditions
Authors: Hassan Anas M. , Zeynalli Mursal , Adila Ahmed S. , Al-Shalabi Emad W. , Kamal Muhammad S. , Patil Shirish
Published: April 2024

Low Salinity Polymer (LSP) injection is a promising hybrid enhanced oil recovery (EOR) technique with immense synergistic advantages in improving injectivity, displacement efficiency, sweep efficiency, polymer rheology, and polymer viscoelasticity. To model the LSP injection, the Polymer-Brine-Rock (PBR) interactions must be precisely captured at core-scale and further upscaled to field-scale predictive model. Also, although the literature has many experimental and theoretical studies on LSP floods, few of these works address the industry's experience with LSP-based EOR at field-scale applications. Therefore, moving from experimental laboratory study to field-scale predictive modeling is an enormous challenge. This contribution describes a pertinent reservoir simulation analysis of an LSP-based EOR method from core-to-field scale. This work employs a proposed MATLAB-Reservoir-Simulation Toolbox (MRST) flow model to gain an in-depth understanding of LSP techniques at the field-scale. This proposed MRST simulator captures the physico-chemical aspects of the LSP flooding, including inaccessible pore volume (IPV), polymer rheology, permeability reduction, and the effects of shear rate and salinity. After successful implementation and validation of the proposed MRST simulator to predict LSP performance at the core scale, field-scale simulations were used to assess LSP injection in a quarter 5-spot well pattern. To identify the optimal LSP injection scenario on oil recovery and oil residual saturation, we carried out a sensitivity analysis by varying the injected water salinity, polymer concentration, and injection scheme.

The field-scale simulation results revealed the positive effect of injection polymer concentration on polymer viscosity, and thus, oil displacement efficiency. Likewise, tertiary polymer flooding may increase volumetric sweep efficiency by reducing gravity underride and sweeping top layers. Also, tertiary low salinity polymer (LSP) flooding might lead to an additional 11% oil recovery OOIP since it would increase both the microscopic and macroscopic sweep efficiencies. Furthermore, the effect of polymer concentration was not much pronounced compared to the effect of water chemistry (i.e., salinity) on oil recovery and remaining oil saturation. Nonetheless, it is thought that polymer concentration may be one of the key parameters significantly boosting sweep efficiency and oil recovery in reservoirs with more viscous oil. Finally, starting early with LSP flooding in the secondary stage improve oil recovery while yielding higher benefits for environmental and economic advantages. The findings of this study suggest that significant attention must be provided to the selection of water salinity, polymer concentrations, and the adjustment of injection strategies for successful LSP flooding in harsh conditioned carbonate reservoirs.
Quantifying Polymer Injectivity and Performance in the Milne Point Oil Field
Authors: Dean R. M. , Aitkulov A. , Edwards R.
Published: April 2024

Polymer floods often collect a large amount of injectivity data that is often overlooked or minimally explored for additional value. This paper uses a plethora of existing field data for numerous polymer injectors to improve injectivity prediction, potentially identify problem wells, and perform polymer QA/QC using existing field wellhead pressure, bottom hole pressure, and rate data.

Existing injectivity models (Aitkulov, et al. 2021) (Jackson, et al. 2019) (Poulsen, et al. 2018) are used to predict performance and determine difference between prediction and actual injectivity. Step-rate tests (SRT) or cases with multiple rates are also used to quantify well performance, constrain, and quantify rheology parameters in the reservoir, and look for bottom-hole pressures approaching the minimum horizontal stress. Polymer flow in tubing is used to determine friction reduction capabilities and is used to double check that polymer rheology is on specification via calibration with known viscosity using Moody diagrams (Moody 1944).

Many wells were found to be below ideal injectivity on both water and polymer, however most of them were easily explained by pattern orientation, e.g., injection well with only one offset producer. The concept of friction factor (fDW) plots vs. Reynolds numbers (Re) are demonstrated for the purpose of performing QA/QC checks on polymer being injected where applicable.
Unveiling the Enigma of Waterflood Inefficiency: A Multifaceted Analysis of Geological, Petrophysical, and Reservoir Dynamics - A Case Study in a Morrowan Clastic Reservoir
Authors: Morgan A. , Ampomah W. , Grigg R. , Wang S. , Czarnota R.
Published: April 2024

The petroleum reservoir represents a complex heterogeneous system that requires thorough characterization prior to the implementation of any incremental recovery technique. One of the most commonly utilized and successful secondary recovery techniques is waterflooding. However, a lack of sufficient investigation into the inherent behavior and characteristics of the reservoir formation in situ can result in failure or suboptimal performance of waterflood operations. Therefore, a comprehensive understanding of the geological history, static and dynamic reservoir characteristics, and petrophysical data is essential for analyzing the mechanisms and causes of waterflood inefficiency and failure. In this study, waterflood inefficiency was observed in the Morrow B reservoir located in the Farnsworth Unit, situated in the northwestern shelf of the Anadarko Basin, Texas. To assess the potential mechanisms behind the inefficiency of waterflooding in the East half, geological, petrophysical, and reservoir engineering data, along with historical information, were integrated, reviewed, and analyzed. The integration and analysis of these datasets revealed that several factors contributed to the waterflood inefficiency. Firstly, the presence of abundant dispersed authigenic clays within the reservoir, worsened by low reservoir quality and high heterogeneity, led to unfavorable conditions for waterflood operations. Furthermore, the use of freshwater for flooding exacerbated the adverse effects of sensitive and migratory clays, further hampering the effectiveness of the waterflood. In addition to these factors, several reservoir engineering issues played a significant role in the inefficiency of waterflooding. These issues included inadequate perforation strategies due to the absence of detailed hydraulic flow units (HFUs) and rock typing, random placement of injectors, and poor quality of the injected water. These external controlling parameters further contributed to the overall inefficiencies observed during waterflood operations in the East half of the reservoir.
A Novel Polymer Gel System for In-Depth Water Conformance in High Temperature and High Salinity Reservoirs
Authors: Lu Meng , Zhang Danhua Leslie , Li Jianshen , Huang Qiushi , Zu Yu , Guo Hongyu , Zhou Nancy , Niu Fangya , Mohanty Kishore
Published: April 2024

Delayed polymer gel systems have been the leading in-depth water conformance control agents in enhanced oil recovery applications. However, most polymer gel systems had limitations to tolerance high temperature and high salinity conditions. The objective of this work is to develop a new delayed polymer gel system that could form stable gels at 80-100 ℃ in brines with salinity up to 200,000 mg/L and a gelation time of more than 3 days.

The gelation tests of a new Acrylamide-ATBS copolymer and a crosslinking agent were performed in anaerobic chambers around 90 ℃ in various synthetic brines with salinity of 50,000 to 200,000 mg/L. Gelation profiles and relationships between gelation time and polymer and crosslinking agent’s concentrations were obtained. Sydansk Gel Code was used to determine gel strength. Sandpack and coreflood experiments were performed to evaluate in-situ gel strength and long-term stability and to measure polymer and crosslinking agent’s adsorption/retention.

The gelation profiles of gelation systems with polymer concentration ranging from 2500-4500 mg/L and crosslinker concentration from 100-1000 mg/L showed that the gelation time was 3-30 days around 90 ℃ with a low pre-gelation viscosity. The gelation time was varied by either the concentration of the polymer or that of the crosslinker and the brine salinity. The gel strength ranged from Code C to Code F. Sandpack and coreflood experiments of injected gelant showed formation of strong gels in-situ with low polymer/crosslinker retention. The permeability reduction of the cores plugged by the polymer gel was greater than 99% and the plugging was effective for more than 12 months.

This work presents a new two-components polymer gel system with low pre-gelation viscosity, long and tunable gelation time, good gel strength and long-term stability to effectively shutoff high permeability channels/zones for in-depth conformance control in high temperature and high salinity reservoirs.
Untethered Downhole Viscosity Logging for EOR Polymer Fluid Degradation Monitoring
Authors: Gonzalez Miguel , Seren Huseyin , Thiel Tim , Hillman Thomas , Ayirala Subhash , Maskeen Lyla , Alkhateeb Abdulaziz , Deffenbaugh Max
Published: April 2024

Enhanced Oil Recovery (EOR) operations based on polymer flooding can be severely impacted if the long-chained polymer molecules used to increase the viscosity of the injected fluid are degraded. This may occur either by mechanical or chemical means at any point of the injection process. Degradation leads to a reduced viscosity, ultimately reducing the effectiveness of the EOR operation. Monitoring the polymer viscosity would help reducing the risk of degradation, which could significantly impact oil recovery rates. Currently, there are no means to perform frequent checks for polymer degradation downhole during injection. We describe a small, untethered downhole tool with an onboard viscometer. The tool is simple and cost-effective, and it can be deployed routinely without need of a wireline logging crew. This instrument may be useful in detecting polymer degradation downhole.
Cyclic Stimulation with Steam and Nitrogen as an Alternative to Improve the Recovery Factor and Energy Efficiency in Colombian Heavy Crude Oil Fields
Authors: Padilla J. M. , Amaya M. P. , Luque I. S. , Osma Laura , Villadiego D. O. , González A. , Pérez R. A.
Published: April 2024

One of the main challenges for exploiting heavy crudes is coupling oil productivity with optimal energy efficiency and low emissions. In that sense, Ecopetrol S.A. has been evaluating EOR technologies, some of them already incorporated in the field development plans, such as the co-injection of steam and nitrogen (N2) in the cyclic stimulation process (CSS), managing to recover a greater volume of incremental oil, reducing the carbon intensity, and optimizing the total heat injected.

In general, the CSS comprises a period of nine (9) days: three days of injecting steam, four days of co-injection (steam through the tubing and nitrogen through the annular), and it ends by injecting steam for two days. The co-injection of steam and nitrogen has been applied in six fields of the Magdalena Middle Valley (MMV) basin, and in the last year, 248 wells were intervened with the objective of improving the efficiency of the injected heat and the response in production. Trying to optimize the field operation of CSS+N2, an exhaustive reservoir engineering analysis, and the development of numerical feasibility studies using a radial single well model built based on representative petrophysical and fluid properties of MMV fields, it was possible to reduce steam volumes by evaluating different injection schemes.

After one year of evaluation, it was found that compared to a conventional steam stimulation cycle, all the wells presented a 30% reduction in carbon intensity (KgCO2/stbo), an increase in energy efficiency by around 27% associated with less energy required to produce a barrel of oil (MMBTU/stbo), represented savings over 4,000,000 USD in natural gas to generate steam and 43% more crude was recovered, additionally the duration of the cycle was extended. According to the numerical evaluation, it is possible to improve these results by finding an injection scheme, which, through post-nitrogen injection for five days, reduces 30% of the volume of steam usually used and improves the indicators of carbon intensity and energy efficiency by 23%. Considering the results obtained, an extended nitrogen injection pilot is proposed for MMV.

Combining field results and experiences with the numerical methodology developed represents a great opportunity for the future of heavy crude oil field production aligned with the carbon footprint reduction goals established in Colombia.