As an enhanced oil recovery method (EOR), chemical flooding has been implemented intensively for some years. Low Salinity WaterFlooding (LSWF) is a method that has become increasingly attractive. The prediction of reservoir behaviour can be made through numerical simulations and greatly helps with field management decisions. Simulations can be costly to run however and also incur numerical errors. Historically, analytical solutions were developed for the flow equations for waterflooding conditions, particularly for non-communicating strata. These have not yet been extended to chemical flooding which we do here, particularly for LSWF. Dispersion effects within layers also affect these solutions and we include these in this work.
Using fractional flow theory, we derive a mathematical solution to the flow equations for a set of layers to predict fluid flow and solute transport. Analytical solutions tell us the location of the lead (formation) waterfront in each layer. Previously, we developed a correction to this to include the effects of numerical and physical dispersion, based on one dimensional models. We used a similar correction to predict the location of the second waterfront in each layer which is induced by the chemical's effect on mobility. In this work we show that in multiple non-communicating layers, material balance can be used to deduce the inter-layer relationships of the various fronts that form. This is based on similar analysis developed for waterflooding although the calculations are more complex because of the development of multiple fronts.
The result is a predictive tool that we compare to numerical simulations and the precision is very good. Layers with contrasting petrophysical properties and wettability are considered. We also investigate the relationship between the fractional flow, effective salinity range, salinity dispersion and salinity retardation.
This work allows us to predict fluids and solute behaviour in reservoirs with non-communicating strata without running a simulator. The recovery factor and vertical sweeping efficiency are also very predictable. This helps us to upscale LSWF by deriving pseudo relative permeability based on our extension of fractional flow and solute transport into such 2D systems.
Two upscaling exercises performed in 2013-14 and 2017-18 on two onshore green fields with conventional to viscous oil are presented, for which the upscaling tried to compensate the effects of grid coarsening, in particular the increase of numerical dispersion and the decrease of heterogeneity. Our methodology was to adjust the water/oil relative permeabilities called pseudo KRs in the coarse scale simulation, in order to reproduce the behavior in terms of pressure, rates, saturations and concentrations of the fine scale model, which was using microscopic rock KRs based on laboratory data.
As the upscaling depends on the fluid injected, it was done separately for waterflood and polymer flood. When done with polymer flood, the concentration of polymer had to be history matched also mainly by adjusting the Todd-Longstaff mixing parameter in addition to the KRs. As upscaling is case dependent, it was performed on several geological models, varying heterogeneity and grid size, but also rock KRs and even precocity of the polymer flood after some waterflood, to test the robustness of the approach.
It was found that pseudo-KRs for waterflood could be slightly degraded for viscous oils, whereas the upscaling was more neutral for conventional oils. This correlates well with field observation for viscous oils, where water production occurs generally a bit quicker than what numerical simulation predicts when using rock KRs, in absence of upscaling.
For polymer floods, which were considered in secondary or early tertiary mode, pseudo KRs were generally improved, mainly because the polymer steepened the saturation fronts, which can be well represented only with small lateral grid size.
The result of both upscaling exercises was that the increment of polymer flood versus waterflood was noticeably higher when computed on high resolution modelling. This is equivalent to saying that when using pseudo KRs resulting from this high resolution matching, the polymer increment on coarse grid is significantly higher than if computed without pseudo KRs. This improves the economic evaluation of the project, increasing the willingness to de-risk and implement early polymer floods on these fields.
The expansion of unconventional resources development has placed emphasis on better understanding of hydraulic fracturing stimulation effectiveness and the area of pay affected by the fracture treatment to optimize well spacing and improve completion and stimulation effectiveness. Existing fracture diagnostic methods such as microseismic monitoring and tiltmeters do not provide information about fracture connectivity to the wellbore. In this paper, we present a chemical tracer flowback based fracture diagnostic and analysis methods to estimate the fractional contribution of each created fracture stage, which is open and connected to the wellbore to help improve field development strategies and provide valuable information on optimal well paths for future drilling and development. The findings out from the stage production contribution profiles using the chemical tracer technology allows engineers to improve stimulation efficiency in multistage hydraulic fracturing horizontal wells applications for completion optimization and production enhancement. Two case histories are presented in which the chemical tracer technology was applied to two horizontal wells. The results of the chemical tracer analysis were correlated to production data, reservoir parameter and other diagnostic tests. The resultant findings from the analysis help evaluate completion and stimulation effectiveness and determine the extent of inter-well connectivity of the fracture network and then used to optimize future completions in the region.
The novel nanomaterial composition described in this paper has been designed to treat moderate to severe losses. The nanomaterial composition comprises an environmentally friendly nanoparticle based dispersion and a chemical activator. The design is based on a delayed activation chemistry to gel up a nanoparticle based dispersion.
Three different types of nanoparticles were used in the study to develop the novel loss circulation material. Two different types of negatively charged nanoparticle based dispersion and one positively charged nanoparticle based dispersion were used in the study. An inorganic activator has been used for the study. The effect of this inorganic activator on the gelation properties of the nanoparticle based dispersion was investigated. The gelling times were evaluated at different temperatures up to 300°F. The effect of activator concentration on the gelling time of the new composition has also been studied. The effectiveness of the newly developed composition as a loss circulation treatment was also evaluated by performing permeability plugging tests to test the plugging capacity of this novel system.
The novel nanomaterial composition is designed so as to have a controllable gelation time under a variety of downhole conditions to allow accurate placement of the treatment fluid inside the wellbore without premature setting of the fluid. It was shown that the gelation time of the treatment composition could be controlled by adjusting the concentration of the activator. The system is designed so as to give a predictable and controllable pumping time, ranging from a few minutes to several hours at over a wide range of temperatures. This is an important advantage as it allows the loss circulation composition to remain pumpable for sufficient time for placement and develops the network structure that leads to gelation, over a predictable period of time. The set gel, which appears as a crystalline solid, could remain homogenous and stay in place thereby preventing loss circulation.
Oil spill is considered as one of the biggest ecological disasters due to the scale of the impact it has, on the ecosystem being affected. Offshore oil spills have proven to be a global concern for marine ecosystem and appropriate measures for their control, prevention and removal of contaminants must be considered as top priority.
This paper entails a detailed study of the various available oil spill clean-up techniques and looks at its advantages and limitations. Further, a grading system for all these methods based on oil type, treatment volume, weather conditions, complexity, water turbulence, time required for results, their environmental impact, cost and efficiency is prepared.
In the case of a spill, oil dispersion behavior acts differently for different kind of fluids on sea water depending on their properties, with the effect of turbulence being one of the critical factors. This paper also focuses on the study of different behavior of crude oil and gasoline on sea water using a commercially available CFD (computational fluid dynamics) tool which utilizes more accurate and relevant mathematical formulations. A multiphase oil spill model has been developed to simulate dispersion of oil spill. A consistent Eulerian approach and Navier-Stokes equations is applied across the model, and the diffusion is employed to simulate oil dynamics in the water. The used Multiphase Oil Spill Model takes advantage of recent developments in the areas of CFD.
Magzymov, Daulet (John and Willie Leone Family Department of Energy and Mineral Engineering and The EMS Energy Institute, The Pennsylvania State University) | Purswani, Prakash (John and Willie Leone Family Department of Energy and Mineral Engineering and The EMS Energy Institute, The Pennsylvania State University) | Karpyn, Zuleima T. (John and Willie Leone Family Department of Energy and Mineral Engineering and The EMS Energy Institute, The Pennsylvania State University) | Johns, Russell T. (John and Willie Leone Family Department of Energy and Mineral Engineering and The EMS Energy Institute, The Pennsylvania State University)
The objective of this paper is to model low-salinity waterflooding by honoring physico-chemical complexity, namely, the effects of reaction kinetics and dispersion. Recent literature provides evidence for the potential of low-salinity water injection to improve oil recovery through wettability alteration through a complex network of reactions. However, there is lack of consensus with respect to the exact chemical species that are responsible for the alteration process. Therefore, in this study, we develop a a simplified binary multiphase reactive transport model that honors the general surface reaction for wettability alteration, but at the same time includes effects of reaction kinetics and dispersion in the governing equations.
We lump the reactants, such as sodium, calcium, and petroleum acids, into two characteristic components based on their contribution to oil or water wetness. The wettability alteration process is modelled as a competition between these primary characteristic components to occupy the rock surface as described by reaction kinetics.
The simulation results show a significant impact of reaction kinetics on the rate of wettability alteration compared to assuming instantaneous equilibrium. In the limiting case of a very slow reaction rate (Da ~ 0), low-salinity injection does not alter the wettability. Particularly, no effect on ultimate oil recovery is observed, regardless of the injected salinity level. For the case of an instantaneous reaction the ultimate oil recovery is sensitive to the injected fluid salinity. Moreover, during fast reactions (Da ~ 10-4), the wettability alteration front moves slower than the injected fluid front caused by excess salt in the solution that desorbs from the rock surface. The delay in wettability alteration is crucial to consider for an appropriate slug size design of low-salinity injection. Lastly, we observe that dispersion does not affect the ultimate oil recovery during wettability alteration as compared to reaction kinetics.
The benefits of a nanoparticle-weighted fluid are numerous, allowing the possibility of high-density drilling fluids, a true alternative to expensive heavy brines, barite-weighted reservoir drill-in fluids and the virtual elimination of barite sag. By using a branched carboxylic acid, rather than a linear molecule as a crystal growth inhibitor during precipitation, true nano-scale dispersions have been achieved that are stable in water, with no detectable agglomeration and that are self-dispersing after drying. This paper proposes that greater steric hindrance and smaller particle sizes are achieved by utilising branched, or chair-like carboxylic acids, rather than the long-chain molecules more commonly used. The use of FTIR, XRD, DLS and SSNRM have been combined to demonstrate that inhibitor concentration is the dominant effect in preventing crystal growth but does not account for particle growth retardation alone.
Spherical nanoparticles with a dispersed ZAvg of 16nm and low contact areas have been created. They produce dispersions with a density of 2.27g/cm3. These dispersions display no detectable ‘sag’ after 428 days in suspension suggesting that colloidal stabilisation has been achieved. This paper also demonstrates that further decreases in particle diameter are possible through a combination of mechanical shear during precipitation and pH modification after precipitation has ceased. An optimum pH post-precipitation of 10.4 is close to that targeted by many water-based reservoir drill-in fluids, further highlighting the possibility of surfactant-inhibited barium sulphate nanoparticles as a density agent for drilling fluids. Using pH to modify the PSD of the nanoparticle dispersions strongly suggests that the dispersions can be tuned to one suitable for the intended operation. The growth inhibitors used during precipitation are low-cost and non-toxic and enable the dry particles to disperse to comparable PSDs after drying to their precipitated values. The technology allows the creation of a high-density brine replacement fluid, presenting a significant cost saving over an alternative such as caesium formate in some applications
Previous research on barium sulphate nanoparticles [
Drilling fluid design for shale plays aims to prevent wellbore instability problems associated with fluid invasion, shale swelling, and cuttings dispersion. Although oil-based mud (OBM) can be used to achieve these goals, environmental and economic concerns limit its application. This research evaluates the potential of using silica nanoparticles (SiO2-NPs) and graphene nanoplatelets (GNPs) as drilling fluid additives in a single formulation to improve shale inhibition and long-term stability of water-based mud (WBM) against temperature effects. The design of the nanoparticle water-based mud (NP-WBM) followed a customized approach that selects the additives according to the characteristics of the reservoir. Characterization of Woodford shale was completed with X-ray diffraction (XRD), cation exchange capacity (CEC), and scanning electron microscopy (SEM). The aqueous stability test and zeta-potential measurements were used to assess the stability of the NPs. NP-WBM characterization included the analysis of the rheological properties measured with a rotational viscometer and the evaluation of the filtration trends at low-temperature/low-pressure (LTLP) and high-temperature/high-pressure (HTHP) conditions. Additionally, dynamic aging was performed at temperatures up to 250°F for thermal stability evaluation. Finally, chemical-interaction tests such as cutting dispersion and bulk swelling helped to analyze the effect of introducing NPs on the inhibition capabilities of the WBM. Conventional KCl/PHPA fluid was used for comparison purposes. The results of this investigation revealed that SiO2-NPs and GNPs acted synergistically with other additives to improve the filtration characteristics of the WBM with only minor effects on the rheological properties. NPs exhibited a high colloidal stability with ζ-potential values below-30 mV, which warrants their dispersion within the WBM at an optimal concentration of 0.75 wt.%. The high thermal conductivity of NPs played a key role in promoting an almost flat trend in the cumulative filtrate for the NP-WBM at aged conditions, whereas KCl/PHPA suffered a drastic increase. Also, NP-WBM preserved 43.97% of its initial cutting carrying capacity, while KCl/PHPA experienced a severe reduction of 95.24% at extreme conditions (250°F). Despite the high illite content of the Woodford shale, the NP-WBM exhibited superior inhibition properties that reduced cutting erosion and swelling effect by 24.48% and 35.24%, respectively, compared to the KCl/PHPA fluid. Overall, this investigation supports the potential use of nanomaterials to enhance the inhibition capabilities and the long-term stability of WBM for unconventional shales, presenting an eco-friendly alternative for harsher environments.
Traditional test methods to evaluate dispersion and inhibition of paraffin wax, which are mainly based on wax gelation and deposition, often fail to distinguish and differentiate between classes of chemistries at a reasonable resolution. Recommended products based on such lab screenings sometimes have a difficult time proving success in the field. The rush for oil production from unconventional shale plays in North America create a need for quick and elaborate testing to effectively evaluate new products for prevention and remediation of known paraffin wax issues. This paper will present a progress made in this area.
For our studies a model oil system was used, which consists of field wax deposit dissolved in kerosene. Testing with a model oil allowed us to focus on the chemistries that are effective against paraffin chains known to cause issues. Several different testing conditions were used to push the ability of the chemistries to function. Light scattering was used to monitor transition from turbidity to sedimentation of paraffin wax from bulk solution under static or dynamic conditions. A total of twelve compounds from three classes of polymers and three classes of surfactants were used in treatment of these oil systems.
With this new lab testing methodology, we have been able to discover new insights on the chemistries used for paraffin wax dispersion and inhibition. In contrast to methods which only measure the end point, light scattering and transmission methodology provides system details at time intervals of 30 sec or higher. The method also allowed us to differentiate chemistries based on their impact on the separation index and sedimentation rate of targeted paraffin chains under stressed conditions by forced precipitation. It was found that certain classes of chemistries are more suited for dispersion and inhibition of waxy condensates once system passed the critical point, while others fail over time. This new approach is fast and versatile and must be used as part of a suite of lab and field screenings for product development and recommendation.
New methodology based on light scattering and transmission of oil systems can provide details not seen before on colloidal stability or instability of waxy crudes under stressed conditions. The method gives an even greater insight to how different chemistries function to mitigate known paraffin issues. Quantitative and reproducible data are obtained allowing faster screening of various chemistries and enhancing product development for new and aging fields.
Iron sulfide scaling can pose a significant threat to flow assurance, especially in sour production systems that yields hydrogen sulfide (H2S). When compared to conventional carbonate and sulfate scales, iron sulfide is difficult to inhibit and various risks (liberation of H2S) are associated with chemical removal. Moreover, efficacy of chemical treatment is poor and often uneconomical; and there is currently no true nucleation inhibitor of iron sulfide identified.
A strictly anoxic static bottle test setup was developed and various traditional scale inhibitors, such as phosphonates, carboxylic acid polymers, as well as new chemistries were screened for iron sulfide nucleation and growth inhibition. Different concentrations of scaling ions (Fe+2 and S2-) were used to mimic the field to field variation in brine composition. The resulting aqueous phases as well as iron sulfide solid products were characterized using various analytical tools including ICP-OES, particle size analyser and Turbiscan.
As expected, conventional scale inhibitors did not show any inhibitory or dispersive effect towards Iron sulfide under tested laboratory conditions. However, a chemistry is identified which can prevent iron sulfide scale deposition at threshold quantities. Specifically, this novel chemistry showed partial iron sulfide nucleation inhibition at early stages and growth inhibition (as high as two orders of magnitude) later. This significant growth inhibition of iron sulfide resulted in excellent dispersion formation that prevents iron sulfide particle aggregation/deposition. Various studies were conducted to understand the chemical-iron sulfide particles interaction and mechanistic aspect of chemical-iron sulfide interaction is identified and discussed. Currently inhibitor packages are being developed for field trials and results will be the subject of future publications.
Efficient mitigation of iron sulfide scaling problem has huge industrial and economic importance in oil and gas production. Based on our current laboratory results, it is anticipated that this chemistry will provide a novel chemical treatment option for iron sulfide scaling control at threshold level whereas orders of magnitude more of conventional scale inhibitors may be required. In addition, this novel chemistry also showed promising outcomes on oil-water partitioning test by making finely dispersed iron sulfide particles water-wet thereby preventing the formation of iron sulfide-crude oil emulsion/pad.