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For a polymer flooding field trial in a heavy oil reservoir on Alaska’s North Slope, polymer retention is a key parameter. Because of the economic impact of retention, this parameter was extensively studied using field core material and conditions. In this paper, multiple types of laboratory measurements were used to assess hydrolyzed polyacrylamides (HPAM) polymer retention, including a brine tracer, effluent viscosity, total effluent organic carbon, and effluent chemiluminescent nitrogen. Retention tests were conducted in different Milne Point Schrader Bluff sands, with extensive permeability, grain size distribution, X-ray-diffraction (XRD), and X-ray fluorescence (XRF) characterizations. Several important findings were noted. Polymer retention based on effluent viscosity measurements can be overestimated unless the correct (nonlinear) relation between polymer concentration and viscosity is used. Polymer degradation (either mechanical or oxidative) can also lead viscosity-based measurements to overestimate retention. Inaccessible pore volume (PV) (IAPV) can be overestimated if insufficient brine is flushed through the sand between polymer banks. Around 100 PVs of brine may be needed to displace mobile polymer to approach a true residual resistance factor and properly measure IAPV. Even for a sandpack with kwsor = 20 md, IAPV was zero for HPAM with a molecular weight (Mw) of 18MM g/mol. Fine-grained particles (<20 µm) strongly impacted polymer retention values. Native NB#1 sand with a significant component of particles <20 µm exhibited 290 µg/g, while the same sand exhibited 28 µg/g after these small particles were removed. Polymer retention did not necessarily correlate with mineral composition. The NB#1, NB#3, and OA sands had similar elemental and clay compositions, but the NB#1 sand exhibited ~10 times higher retention than the NB#3 sand. Polymer retention did not necessarily correlate with permeability. NB#1 sand exhibited much higher retention than OA sand, even though NB#1 sand was twice as permeable as OA sand. No evidence of chromatographic separation of HPAM molecular weights was found in our experiments. Although retention tended to be greater without a residual oil saturation (than at Sor), the effect was not strong. Aging a core (with high oil saturation) at 60°C reduced HPAM retention by a factor of two. Under similar conditions, polymer retention was greater for a higher Mw HPAM (18MM g/mol) than for a lower Mw HPAM (10 to 12MM g/mol). In many cases with high polymer retention values (e.g., 240 µg/g), polymer arrival at the end of the core was relatively quick, but achieving the injected concentration occurred gradually over many PVs. This effect was not caused by chromatographic separation of polymer molecular weights. Results from modeling of this behavior were consistent with concentration-dependent polymer retention. The form assumed for the retention function in a simulator can have an important impact on the timing and magnitude of the oil response from a polymer flood. Field-based observations can underestimate polymer retention, depending on when the tracer and polymer concentrations were measured and the assumptions made about reservoir heterogeneity.
Ellafi, Abdulaziz (University of North Dakota) | Jabbari, Hadi (University of North Dakota) | Wan, Xincheng (University of North Dakota) | Rasouli, Vamegh (University of North Dakota) | Geri, Mohammed Ba (Missouri University of Science and Technology) | Al-Bazzaz, Waleed (Kuwait Institute For Scientific Research)
Improvement in hydrocarbon production from unconventional reservoirs, such as the Bakken Formation, is driven by drilling horizontal wells and multi-stage hydraulic fracturing. The main objective of a frac treatment is to create complex fracture geometry to increase well/reservoir contact area (i.e. large SRV; stimulated reservoir volume) by injecting larger fluid volume and high proppant concentration. The success of the treatment relies substantially on selecting appropriate fracturing fluids that transport the proppant particles deep enough into the fractures. This research is aimed at studying the capability of high-viscosity friction reducers (HVFRs) by examining the produced water from the Bakken Fm through an integral approach. The application of surfactant as an additive to the HVFRs was investigated in high TDS (total dissolved solids) conditions. To assess the current industry practice for hydraulic fracturing in the Williston Basin, these tasks were performed: a) rate trainset analysis (RTA) to evaluate the current completion in Bakken wells by estimatingfracture half-length and SRV properties, b) 2D/3D fracture simulation to study the impact of treatment fluids on fracture-network/SRV properties, and c) reservoir simulation to predict the estimated ultimate oil recovery (EUR) for identifyingoptimum hydraulic fracturing design. The results show that using a surfactant mixed with the frac fluids can lead to improved proppant transport, fracture conductivity profile, and thus higher effective fracture-half length compared tocurrent practice. It was found that such a frac fluid mixed with surfactant can result in improved EUR by as high as 15% compared with linear gel and HVFRs with produced water (HVFR-PR) due to larger SRVs. Reusing produced water, including formation and flow back water can be a wise decision to minimize environmental footprint and reduce operating costs. The findings from this research can be applied to other unconventional shale plays, such as Eagle Ford and Permian Basin for comparison and optimization purposes.
Ba Geri, Mohammed (Missouri University of Science and Technology) | Ellafi, Abdulaziz (University of North Dakota) | Flori, Ralph (Missouri University of Science and Technology) | Belhaij, Azmi (Saudi Metal Coating Company) | Alkamil, Ethar H. K. (University of Basrah)
Nowadays, as the worldwide consumption of hydrocarbon increases, while the conventional resources beings depleted, turning point toward unconventional reservoirs is crucial to producing more additional oil and gas from their massive reserves of hydrocarbon. As a result, exploration and operation companies gain attention recently for the investment in unconventional plays, such as shale and tight formations. A recent study by the U.S. Energy Information Administration (EIA) reported that the Middle East (ME) and North Africa (NF) region holds an enormous volume of recoverable oil and gas from unconventional resources. However, the evaluation process is at the early stage, and detailed information is still confidential with a limitation of the publication in terms of unconventional reservoirs potential. The objective of this research is to provide more information and build a comprehensive review of unconventional resources to bring the shale revolution to the ME and NF region. In addition, new opportunities, challenges, and risks will be introduced based on transferring acquiring experiences and technologies that have been applied in North American shale plays to similar formations in the ME and NF region. The workflow begins with reviewing and summarizing more than 100 conference papers, journal papers, and technical reports to gather detailed data on the geological description, reservoir characterization, geomechanical property, and operation history. Furthermore, simulation works, experimental studies, and pilot tests in the United States shale plays are used to build a database using the statistic approach to summarize and identify the range of parameters. The results are compared to similar unconventional plays in the region to establish guidelines for the exploration, development, and operation processes. This paper highlights the potential opportunities to access the unlocked formations in the region that holds substantial hydrocarbon resources.
Ba Geri, Mohammed (Missouri University of Science and Technology) | Flori, Ralph (Missouri University of Science and Technology) | Ellafi, Abdulaziz (University of North Dakota) | Noles, Jerry (Coil Chem LLC) | Essman, Jacob (Coil Chem LLC) | Kim, Sangjoon (Coil Chem LLC) | Alkamil, Ethar H. K. (University of Basrah)
Hydraulic fracturing operation requires securing sufficient water resources to access unlocked formations. Successful treatment depends on the fracture fluids that mainly consists of water-based fluid with a low percentage of chemical additives around 1%. Therefore, the oil and gas industry are considered as the largest freshwater consumers by 3 to 6 million gallons of water per well based on a number of fracturing stages. As a result, the traditional water resources from subsurface and surface are getting depleted, and availability of freshwater is becoming more difficult with high cost due to continued demand. For example, operator companies in West Texas face many challenges, including a recent increase from USD 3 to 10 per m3 of freshwater. In addition, transporting process of the raw water to the fracture sites, such as Bakken has an environmental impact, and expensive costs up to USD 5/bbl, while costs of water disposal in range of USD 9/bbl.
This paper aims to study the produced water as alternative water-based fluid with high viscosity friction reducers (HVFR) to reduce environmental footprints and economic costs. To address utilizing produced water as an alternative capable water resource that may use during fracturing treatment, this research presents an experimental investigation associated with using the Permian high-TDS brine water with HVFRs. This work includes experimental research, case studies, and guidelines work on recent improvements on using HVFR to carry proppant and capture the optimum design in fracturing operations. Moreover, the research conducted scaled lab friction measurements that can in turn to be used to improve forecasting of frictions in the field, and therefore of expected surface treating pressures during fracture treatments. Evaluating pipe friction as a function of time to compare HVFRs efficacy in lab and field conditions as well as to predict maximum injection rate during a frac job is investigated.
The outcomes show that high-TDS Permian water with highest dosage of HVFRs had instantaneous pressure reduction effect in 10 seconds while low dosage of HVFRs had lost the effect slowly after 4 min. 30 sec. Also, the results of this study show that the variation of viscosity and pressure reduction at higher shear rate is small. The warm temperature helped rapid polymer dispersion and provided better environment to polymer hydration leads to rapid pressure reduction. Finally, successful implementation in Wlofcamp formation shows that the operation treating pressure reduced from 11,000 to 8,000 psi. The general guidelines obtained can promote the sustainability of using hydraulic fracturing treatment to produce more oil and gas from unconventional resources without considering environmental issues.
In unconventional reservoirs, such as Bakken Fm, the stimulation application is the required method to develop and produce economically from this vast reserve. However, the production process is still only through primary depletion mechanism with low recovery factor in ranging of 3-5% due to sharp decline in oil production by depletion in natural fracture networks as well as unsuccessful implementation hydraulic fracturing design. This paper aims to investigate the application of HVFRs with surfactant in high TDS condition to enhance Bakken oil wells production performance using an integral methodology between 3D/2D Pseudo hydraulic fracturing simulator and numerical reservoir simulation. Four types of fracturing fluids as follows: Linear Gel, HVFR-A (mixed with freshwater), HVFR-B (mixed with produced water plus surfactant as additives), and HVFR-C (mixed with produced water) were tested using an integral approach. The workflow in this paper was started by modeling the optimal fracture half-length using 2D/PKN model based on the slurry volume per stage. As a next step, the optimum pump schedule was created using 3D Pseudo hydraulic fracturing simulator. Furthermore, the sensitivity analysis was performed on HVFR-B at different pump rate, final proppant concentration, and proppant size to investigate the proppant transport and production performance. Finally, reservoir simulation tool was utilized to investigate the changing in fracture parameters and evaluating the Bakken oil production. The results showed that HVFRs with surfactant is the optimum hydraulic fracture fluids that showed better performance in proppant transport, which responded by high fracture capability to improve oil production. The findings can be applied and compared to other unconventional shale plays, such as Eagle Ford and Permian Basin.
Ba Geri, Mohammed (Missouri University of Science and Technology) | Ellafi, Abdulaziz (University of North Dakota) | Flori, Ralph (Missouri University of Science and Technology) | Noles, Jerry (Coil Chem LLC) | Kim, Sangjoon (Coil Chem LLC)
The success of hydraulic fracture treatment can be evaluated by measuring fracture conductivity and regained permeability. However, selecting the suitable fracture fluid system plays an essential role to minimize or eliminate the formation damage. To address the potential formation damage during fracturing treatment, this research presents a comprehensive review of a good number of published papers that are carefully reviewed and summarized including experimental research, case studies, and simulation work on recent improvements of using HVFR to carry the proppant and capture the optimum design in fracturing operations. This paper also provides formation damage mechanisms such as chemical, mechanical, biological, and thermal. Moreover, the research explains the fracture damage categories including damage inside fracture and damage inside the reservoir. The advantages of using HVFRs are also fully explained. Experimental rheological characterization was studied to investigate the viscoelastic property of HVFRs on proppant transport. The successful implication of utilizing HVFRs in the Wolfcamp formation, Permian Basin was discussed.
The findings of this research are analyzed to reach conclusions on how HVFRs can be an alternative fracture fluid system of many unconventional reservoirs. Comparing to the traditional hydraulic fracture fluids system, the research shows the many potential advantages that HVFR fluids offer, including superior proppant transport capability, almost 100% retained conductivity, around 30% cost reduction, and logistics, such as minimizing chemicals usage by 50% and operation equipment on location, reduce water consumption by 30%, and environmental benefits. Finally, this comprehensive review addresses up-to-date challenges and emphasizes necessities for using high viscosity friction reducers as alternative fracture fluids.
Ba Geri, Mohammed (Missouri University of Science and Technology) | Ellafi, Abdulaziz (University of North Dakota) | Flori, Ralph (Missouri University of Science and Technology) | Noles, Jerry (Coil Chem LLC) | Kim, Sangjoon (Coil Chem LLC)
Viscoelastic property of high-viscosity friction reducers (HVFRs) was developed as an alternative fracturing fluid system because of advantages such as the ability to transport particles, higher fracture conductivity, and potential lower cost due to fewer chemicals and equipment on location. However, concerns remain about using HVFRs to transport proppant in DI water and harsh brine solution (e.g. 2wt% KCl and 10 lbs. brine). The primary objective of this study is to investigate the viscoelastic property that can help to understand the true proppant transporting capacity of fracturing fluids in high-TDS environment.
To address the evaluation performance of HVFRs, a comprehensive review of numerous papers associated to viscoelastic property of hydraulic fracturing fluids were investigated and summarized. This paper also provides a full comparison study of viscosity and elastic modulus between HVFRs and among fracturing fluids such as xanthan, polyacrylamide-based emulsion polymer, and guar. Moreover, viscosity profiles and elastic modulus were conducted at different temperatures. Better proppant transportation effect though higher viscosity through Stoke's law and the effect on proppant transportation from elastic modulus comparison were also investigated. Finally, HVFR Conductivity test and successful field test result were explained.
The results of the experimental work show that viscoelastic property HVFRs provides good behavior to transport proppant. Viscosity profile decreased slightly as the temperature increased from 75 to 150 when the DI water was used. While using 10 lbs. Brine the viscosity was reduced by 33%. The longer polymer chains of HVFR indicated better elastic modulus in DI water. The elastic modulus also indicated that the highest values at frequency 4.5 Hz from each amplitude, and lower values as amplitude was increased. Although high molecular weight HVFRs were utilized on the conductivity test, the results observed that the regained permeability was up to 110%. Finally, the promising results from the case study showed that using HVFRs could be performed economically and efficiently for the purpose of proppant transportation and pressure reduction in high TDS fluids.
In this study, conceptual numerical simulation models, with geomechanical properties incorporated, were employed to assess whether polymer flooding or a surfactant EOR process could be viable; with minimal damage to permafrost. These simulations considered the geological subdivisions of permafrost distribution in the subsurface which included: an active layer (seasonally frozen ground); taliks (unfrozen ground between the base of the active layer and permafrost layer and within the permafrost layer); and the unfrozen layer below the permafrost zone. In addition, a major oil zone was included in the model underlying the permafrost section. Significant oil recovery values were predicted, both for injection of polymer solutions and surfactant-polymer solutions and with both horizontal and vertical wells. Surprisingly, addition of surfactant provides lower oil recovery than for polymer flooding alone (under same injection slug size, when all subdivisions were considered in the model). This result appeared to occur because the thermodynamics build into models allows the surfactant formulation to freeze easier than the polymer solution without surfactant. This freezing depletes the surfactant bank, and therefore, lowers oil recovery. On the other hand, this freezing actually promotes growth of the permafrost, whereas, injection of polymer alone causes a mild thawing of the permafrost. One might question whether the thermodynamics built into the simulator are correct, but this result does emphasis that in addition to temperature, the chemistry of the injected formulation may be important in determining the fate of the permafrost. At a certain well distance to permafrost (1,640 ft), horizontal injection wells cause greater thawing of permafrost than vertical wells, when wellbores are close to the taliks. Higher concentration and viscosity of polymer slugs have small potential for thawing permafrost, largely because of the injectivity reduction during polymer flooding (thus allowing slower heat dissipation). Examination of polymer injection as a function of pressure, temperature, and mean stress, suggests that subsidence of permafrost could be negligible. The effects on permafrost subsidence increases modestly as the polymer slug size increases, and decreases modestly as the surfactant-polymer slug size increases. As huge heavy oil reserves exist in Canada and Alaska's North Slope regions, continued resource development in these regions is likely. Therefore, a thorough understanding is required in considering the long-term impact on permafrost stability with the use of modern EOR processes implemented in this unique environment.
The utilization of synergistic mixtures of nanoparticles (NPs) and surfactants for enhanced oil recovery (EOR) has drawn increasing scientific attention. In this study, a series of coarse-grained (CG) molecular dynamics (MD) models were built to study the behaviors of NPs and surfactants in the vicinity of the oil/water interface. Hydrophilic, hydrophobic, and amphiphilic NPs were constructed to investigate the effect of hydrophobicity on the ability of NPs in term of interfacial tension (IFT) reduction. The synergistic effect of surfactants and NPs were also studied.
Surfactants and amphiphilic NPs can both accumulate at the interface of oil and water, while hydrophilic and hydrophobic NPs stay in water or oil phase. The NPs with various ratios of hydrophobic to hydrophilic domains were investigated to determine the types of NPs that result in the most IFT reduction. The comparison of IFTs indicates that amphiphilic NPs has a better ability to assist surfactants in further reducing the interfacial tension. Meanwhile, surface modification and the presence of surfactants can prevent the aggregation of NPs.
These MD simulation results allow us to figure out the physical behavior of NPs and surfactants at the oil/water interfaces. Analysis of the results can further assist the NPs synthesis for surfactant and/or surfactant-nanoparticle EOR applications in unconventional reservoirs.
Enhanced Oil Recovery (EOR) is well known for its potential to produce residual oil after the primary and secondary oil recovery. The residual oil is trapped in the narrow throat due to high capillary pressure, which is influenced by rock wettability and oil/water interfacial tension (IFT) (Wu et al., 2008). Surfactants have been widely investigated and employed in the EOR process to reduce the IFT and to alter the wettability (Sheng et al. 2015; Kamal et al., 2017; Negin et al., 2017). However, during the surfactant flooding, surfactants can adsorb onto the rock surfaces. This may result in the reduction of their concentrations, which significantly reduce the efficiency of surfactants in practical applications. The high cost of surfactants also makes this potential loss a critical issue. Many researchers have focused their studies on reducing the adsorption of surfactants by adding various materials in the chemical formulations.
Martini, Brigette (Corescan Inc.) | Bellian, Jerome (Whiting Petroleum Corporation) | Katz, David (Encana Corporation) | Fonteneau, Lionel (Corescan Pty Ltd) | Carey, Ronell (Corescan Pty Ltd) | Guisinger, Mary (Whiting Petroleum Corporation) | Nordeng, Stephan H. (University of North Dakota)
Hyperspectral core imaging studies of the Bakken-Three Forks formations over the past four years has revealed non-destructive, high resolution, spatially relevant insight into mineralogy, both primary and diagenetically altered that can be applied to reservoir characterization. While ‘big’ data like co-acquired hyperspectral imagery, digital photography and laser profiles can be challenging to analyze, synthesize, scale, visualize and store, their value in providing mineralogical information, structural variables and visual context at scales that lie between (and ultimately link) nano and reservoir-scale measurements of the Bakken-Three Forks system, is unique.
Simultaneous, co-acquired hyperspectral core imaging data (at 500 μm spatial resolution), digital color photography (at 50 μm spatial resolution) and laser profiles (at 20 μm spatial and 7 μm vertical resolution), were acquired over 24 wells for a total of 2,870 ft. of core, seven wells of which targeted the Bakken-Three Forks formations. These Bakken-Three Forks data (~5.5 TB) represent roughly 175,000,000 pixels of spatially referenced mineralogical data. Measurements were performed at a mobile Corescan HCI-3 laboratory based in Denver, CO, while spectral and spatial analysis of the data was completed using proprietary in-house spectral software, offsite in Perth, WA, Australia. Synthesis of the spectral-based mineral maps and laser-based structural data, with ancillary data (including Qemscan, XRD and various downhole geophysical surveys) were completed in several software and modelling platforms.
The resulting spatial context of this hyperspectral imaging-based mineralogy and assemblages are particularly compelling, both in small scale micro-distribution as well as borehole scale mineralogical distributions related to both primary lithology and secondary alteration. These studies also present some of the first successful measurement and derivation of lithology from hyperspectral data. Relationships between hyperspectral-derived mineralogy and oil concentrations are presented as are separately derived structural variables. The relationship between hyperspectral-based mineralogy to micro-scale reservoir characteristics (including those derived from Qemscan) were studied, as were relationships to larger-scale downhole geophysical data (resulting in compelling correlations between variables of resistivity and hyperspectral-mineralogy). Finally, basic Net-to-Gross calculations were completed using the hyperspectral imaging data, thereby extending the use of such data from geological characterizations through to resource estimations.
The high-fidelity mineralogical maps afforded by hyperspectral core imaging have not only provided new geological insight into the Bakken-Three Forks formations, but ultimately provide improved well completion designs in those formations, as well as a framework for applying the technology to other important unconventional reservoir formations in exploration and development. The semi-automated nature of the technology also ushers in the ability to consistently and accurately log mineralogy from multiple wells and fields globally, allowing for advanced comparative analysis.